ANALYSIS OF

ANALYSIS OF

THE PETROLEUM TECHNOLOGY ADVANCES

THROUGH APPLIED RESEARCH

BY INDEPENDENT OIL PRODUCERS



INTERIM REPORT

(TASK 2)







September 1999









Study performed under Contract No.

DE-AC75-98SW43123-1









Prepared for

U.S. Department of Energy

National Petroleum Technology Office

TABLE OF CONTENTS





SUMMARY……………………………………………………………………………………………...1



INTRODUCTION...…...………………………………………………………………..………………3



BACKGROUND…………………………………………………………………...……………………7



PROJECT-BY-PROJECT RESULTS……………………………………………..………………...10



DISCUSSION…………………………………………………………………………………………..15



CONSUSIONS & RECOMMENDATIONS………………………………...……………………….17



APPENDIX A - EVALUATION FACT SHEETS…………………………………...……………....20



APPENDIX B - LESSONS LEARNED PROJECT DISCUSSION.……………………………..…29









LIST OF TABLES





TABLE 1 – SUMMARY RESULTS FOR “UNSUCCESSFUL” PROJECTS…..………………………1



TABLE 2 - CONTRACT SUMMARIES…………………………………………………….……………..5



TABLE 3 - TECHNOLOGY AREAS AND PROJECT OUTCOME……..………………………..…....6

ANALYSIS OF

THE PETROLEUM TECHNOLOGY ADVANCES

THROUGH APPLIED RESEARCH

BY INDEPENDENT OIL PRODUCERS



INTERIM REPORT

(TASK 2)









SUMMARY





The projects cost-shared under the 1995-1998 DOE/NPTO program, “Petroleum Technology Advances

through Applied Research by Independent Oil Producers,” were very largely successful. Fourteen of 22

successfully met their project objectives and contributed to one or more program objectives (prolonged

productive life, increased production and/or reserves, an improved environmental performance.



Of the eight projects that were less than fully successful, four were partially successful in advancing useful

technologies and three more contributed useful technical information. The projects that were less than fully

successful are summarized in Table 1 by operator, and project technology description, and a brief statement

of the outcome. They are ordered from partially successful to completely unsuccessful.



Table 1

Summary Results for "Unsuccessful" Projects



Operator Technology Results



Spring DHI tool Equipment worked, but formation capacity inadequate

Cleary Horizontal Drilling. Fluid level increased, but horizontal hole was lost

Brothers 3-D Seismic Algorithm. Mapped top of Ellenburger; uneconomic to drill

Double-Eagle 3-D Seismic Survey. Canceled one well, drilled one dry hole, uneconomic.

EDCO Horizontal Drilling. Unable to complete drilling; No increase in production

Keener Telluric Survey. Gave inaccurate and/or unreliable results, dry hole

Diamond Thermal. Heated some of the formation, but no oil was produced

Pounds Oxygen Activation Log. Log not applicable, no new technology applied



This report summarizes the results of these eight projects and the lessons learned from them. Subsequent

reports will assess the 14 that more fully met project and program objectives.



Of the eight projects that did not meet program goals, four projects were stet successful, as summarized

below, roughly in order of their success:





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Project 17. Cost Effective Water Disposal, operated by Harry A. Spring - The proposed technology

performed as designed, but the application was unsuccessful. The Down Hole Injection Tool (DHI Tool)

used in the project appears to have functioned as designed. However, the attempted application failed

because the producing formation produced significantly more water than had been anticipated and the target

injection zone had too low permeability to accept all of the water being produced. The well had to be

abandoned because conventional water disposal was uneconomic.



Project 1. Horizontal Drilling to Increase Production, operated by Cleary Exploration LLC - The project

utilized technology which is well developed in other fields, but the application was unsuccessful. Although

the horizontal hole was completed, the lateral section collapsed before a sustained production test could be

run. The attempted application failed due to problems created during drilling and possibly to inadequate

completion design. This project did however, indicate sufficient production potential to warrant further

evaluation in Task 3.



Project 3. Improved 3-D Seismic Processing Techniques, operated by Brothers Production Co. - The

technology was used to identify several exploitation prospects, but drilling activities were suspended due to

low oil prices. This 3-D seismic project utilized a new interpretation technique and resulted in confidently

mapping reflections on top of the target formation. However, the accuracy of the interpretation has not yet

been fully demonstrated. Although several prospects were identified from the reinterpreted 3-D seismic data,

low oil prices during the project time period and the uncertainty of current oil prices have put exploitation

drilling activities on hold. To date, no wells have been drilled to test the target formation based on the

reinterpreted 3-D seismic data. Drilling of several of the prospects will be necessary to determine if the

relative success rate can be improved by the reinterpreted data.



Project 4. Integrated Exploration Using 3-D Seismic, operated by Double-Eagle Enterprises, Inc. - The

technology was unsuccessful, but the lack of success may have been due to a misinterpretation of the

seismic data. A dry hole was drilled on a prospect identified from the 3-D seismic data interpretation. Re-

examination of the 3-D seismic data after the dry hole was drilled indicates that the structural anomaly

identified from the 3-D seismic data may have been a misinterpretation of the data. Further drilling

activities were suspended indefinitely due to low oil prices existing at the time of the project. This project

will require drilling several additional prospects to determine if the relative success rate can be improved by

the use of 3-D seismic data, in reservoirs such as this to augment existing 2-D interpretations.



The other four "unsuccessful" projects did not produce successful results in terms of the program objectives,

but at least three of them contributed useful technical information. Again ranked in rough order of their

contributions, they are:



Project 2. Horizontal Drilling for Improved Wellbore Drainage, operated by EDCO Producing, Inc. -

The project utilized technology that is well developed in other fields, but the application failed in what may

be a difficult situation for application of this technology. The horizontal drilling attempt was unable to be

completed due to hole problems resulting from an inability to maintain directional stability in what may be a

rather difficult formation to drill in. Any additional application in this formation will require careful

evaluation to determine if horizontal drilling is feasible in this reservoir of this type before the concept of

improved production from a horizontal wellbore can be further evaluated.



Project 5. Telluric Surveys, operated by Keener Oil & Gas Co. - The application failed due to new, under-

developed experimental technology. The telluric survey interpretation was not accurate enough to avoid the

drilling of a dry hole. The structural anomaly identified from the telluric survey data was considerably lower

than indicated and the formation was water-filled at that location. This technology is in a very early stage of

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development and will require considerable development to determine its applicability. The technology has

considerable cost savings and environmental potential if it can be eventually developed.



Project 9. Stimulating Formations Thermally, operated by Diamond Exploration, Inc. - The application

failed due to new, under-developed experimental technology and possibly to low oil saturation in the

formation. Thermally heating the reservoir using electrical current produced no measurable results. Even

though the temperature of the formation at each of the three electrical probe wells was increased, the

formation at the center producing well showed no indication of temperature change and no oil was

produced. It is difficult to determine if the lack of production was the results of technology failure or due to

a low oil saturation in the formation (21-38 % as indicated by core analysis). This technology is in a very

early stage of experimental development and would require considerable additional research and design to

determine if the technology concept is even feasible.



Project 19. Oxygen Activation Log, operated by J. R. Pounds, Inc. - The application failed because the

proposed technology was not utilized. The proposed Oxygen Activation Log technology was not applicable

to the particular situation and thus the log was not used to remediate the production problem.



Although these eight projects did not result in an increase in production or reserves or in successful

development of new technology, an improved environmental performance, seven of them did make

substantive contributions to the goals of their sponsor, DOE/NPTO.





INTRODUCTION





In 1995, the United States Department of Energy, through its National Petroleum Technology Office

(DOE/NPTO), initiated a program entitled, entitled "Petroleum Technology Advances Through Applied

Research by Independent Oil Producers", informally referred to as “Support to Independents”. Between

1995 and 1998, 22 projects (Table 2) were selected to help small independent operators find commercial

solutions to specific, local production problems. The program, in the form of cost-shared assistance, was

aimed at encouraging small domestic producers to apply higher risk, unfamiliar technologies and/or novel,

unproven approaches to solve their particular operational problems through R&D demonstration projects.

Projects were selected to demonstrate various techniques to solve local problems that also had the potential

for broader application to additional, similar fields (based on geology, location, and/or operating practices).

The program was intended to help the small independent oil producers, which usually lack the technical staff

to study new technologies and access to risk capital to implement new processes. The goal of NPTO's

program was to identify and publicize methods to maintain current production levels and to help curtail the

premature loss of domestic production due to low oil prices and high operating costs.





The specific objectives of the program were to:



 Extend economic production of domestic fields.

 Increase ultimate recovery in known fields.

 Broaden information exchange and technology application.



This report describes the work performed to date in evaluating these individual projects. The objective of

analyzing the program is to assess the extent of success in helping the participants solve their problems and



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the implications of these solutions for other operators. Results of the evaluations completed under this work

can be used to improve the effectiveness of the DOE/NPTO R&D and technology transfer efforts.



Work completed to date under this evaluation effort has collected and analyzed information on each of the

projects completed. Task 1 of this analysis completed a review of this information for each of the twenty-

two projects. All reports pertaining to the 22 projects were compiled and reviewed, including technical and

economic data submitted by operators. Additional information was gathered through telephone interviews

with many of the operators in order to collect key missing elements needed for analysis. The results of the

data collection efforts were used to determine which projects were technically successful and which were

unsuccessful in terms of achieving the specified objectives of the program. The program objectives to be

accomplished by each demonstration project included increasing production rates, increasing reserves, or

developing new production technology. Task 1 of the analysis was completed and the results were discussed

with the NPTO project managers on April 26, 1999. Fourteen projects successfully met the defined project

objectives and eight projects failed to meet one or more goals and objectives of the program. These projects

are identified in TABLE 3, with the "unsuccessful" projects, the subject of this report, highlighted.



Task 2 of the analysis required a review of the individual "unsuccessful" projects identified in Task 1 to

determine the principal cause for the failures, e.g., the extent to which the failure resulted from operational

problems, from technical factors, or economic conditions at the time of the test. This analytical effort was

also designed to determine and report program-wide lessons learned from the initial phase. The results are

presented in this report. The key results of the technical review of the unsuccessful projects have been

compiled into a "lessons learned" format for future reference in managing and administering the ongoing

Support to Independents program. APPENDIX A of this report contains individual detailed evaluation fact

sheets for each of the unsuccessful projects and APPENDIX B contains a detailed discussion of the "lessons

learned" for each of the unsuccessful projects.



Ongoing work under Task 3 will expand this analysis, completing a thorough technical and

economic evaluation of the fourteen technically successful projects identified in Task 1. The

analysis will determine (where possible, depending on the data and information available), the

economic success and direct benefits of these projects in terms of oil produced, cost reductions, and

tax revenues generated.





Overall, the Support to Independents program has generated substantial gains in key technologies

that can be applied by independent operators. Of the projects identified as "unsuccessful" nearly all

showed promising technical findings that could be utilized to focus additional research or that could

increase the chance of success of future applications. Seven of the eight “unsuccessful” projects

provided additional insights and/or technical information useful to future technology development

efforts. The projects were also adversely affected by the fall in oil prices during the project

implementation period. This appears to have detracted from operators' resolve in completing

additional tests that could have proved successful. With focused, additional research and expanded

field testing, many promising new technologies could be made available through this program to

increase production and maintain critical industry infrastructure.









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TABLE 2 Contract Summary



Project Technical Project Project Duration Sub Contract Cost

Subcontractor Location Area Start End Date Months Field/Formation # Share

Date Operator DOE/NPTO TOTAL

Cleary Expl. Oklahoma Horizontal 08-01-96 07-30-97 12 Hunton Formation Dolomitic G4P70039 $115,500 $50,000 (30%) $165,000

Drilling. Limestone (70%)

EDCO Producing Ohio Horizontal 05-03-96 08-01-96 2 Trempealeau Formation G4P60386 $39,000 $39,000 (50%) $78,000

Drilling. (50%)

Brothers Prod. Texas 3-D Seismic 04-15-96 09-15-96 5 Ellenburger/Strawn Dolomite G4P60306 $450,000 $50,000 (10%) $500,000

(90%)

Double Eagle Ent. Oklahoma 3-D Seismic 05-30-96 12-31-97 19 Wilcox Formation G4P60320 $240,000 $50,000 (17%) $290,000

(83%)

Keener O&G Oklahoma Telluric 10-15-95 12-31-95 3 Wilcox Sand G4P51722 $100,000 $50,000 (33%) $150,000

(67%)

Univ. of AL/Cobra Alabama FMI Log 10-15-95 10-14-96 12 Frisco City Sandstone G4P50139 $25,000 $25,000 (50%) $50,000

(50%)

Sandia Oper. Corp. Texas Coring System 10-15-95 10-14-96 12 First Cole Sandstone G4P51726 $70,800 $50,000 (41%) $120,800

(59%)

Dakota Oil Prod. Wyoming Inert Gas Inj. 10-15-95 10-14-96 12 Lakota Sand G4P50140 $50,000 $47,202 (49%) $97,202

(41%)

Diamond Expl. Kansas Thermal 10-15-95 04-15-96 6 Cottage Groove Sand G4P51723 $49,500 $49,500 (50%) $99,000

Stimulation (50%)

Edmiston Oil Co. Kansas Microbial IOR 06-30-96 07-01-97 12 McLouth Sand G4P60387 $117,900 $50,000 (30%) $167,900

(70%)

X-Trac Energy Utah Extraction 04-01-97 11-30-97 8 PR Springs and Asphalt Ridge G4P70040 $97,359 $50,102 (34%) $147,359

Sandstones (66%)

James Engr. Ohio Computer 04-30-96 12-31-97 20 Clinton/Rose Run Fields G4P60318 $46,500 $47,500 (50%) $94,000

Software (50%)

K-Stewart Petro Oklahoma Well Stimulation 09-16-96 07-28-97 11 Morrow Formation G4P60397 $623,400 $50,000 (7%) $673,400

(93%)

ITM California Gravel Pack 06-17-97 04-30-98 11 Kern County G4P70090 $50,000 $49,500 (50%) $99,500

(50%)

Sipple Oil Co. Kentucky Fracture 04-01-96 03-31-97 12 Coniferous Dolomite Formation G4P60307 $60,818 $49,753 (45%) $110,571

Treatment (55%)

Grace Petro Oklahoma Polymer Flood 10-01-95 05-30-97 8 Bartlesville Sand G4P51721 $56,000 $50,000 (47%) $106,000

(53%)

Harry A. Spring Oklahoma Water Disposal 05-30-96 05-29-97 12 Carmichael Sand G4P60383 $27,500 $27,500 (50%) $55,000

(50%)

Kenneth Y. Park Oklahoma Polymer 10-15-95 10-14-96 12 Bartlesville Sand G4P51725 $50,458 $45,775 (48%) $96,233

Treatment (52%)

J. R. Pounds, Inc. Mississippi Oxygen Act. Log 04-15-96 04-14-97 12 Rodessa Sand G4P60305 $72,400 $50,000 (41%) $122,400

(59%)

Rock Is. Serv. Co. West Virginia Microbial 04-01-97 03-31-98 12 Salt Sand G4P70041 $46,430 $46,430 (50%) $92,860

Cleanup (50%)

Speir Oper. Co. Indiana Microbial 10-15-95 10-14-96 12 Cypress Limestone G4P50724 $48,775 $48,775 (50%) $97,550

Cleanup (50%)

Tenison Oil Co. Louisiana CaCO3 06-30-96 05-13-97 11 Hosston Sandstone G4P60385 $41,690 $37,400 (47%) $79,090

Prevention (53%)

TABLE 3 Technology Areas and Project Outcome



Technology Area Project Title Operator Outcome

Drilling

1. “Horizontal Drilling to Increase Production” Clearly Exploration L.LC. Unsuccessful

2. “Horizontal Drilling for Improved Well bore Drainage” EDCO Producing, Inc. Unsuccessful

Exploration

3. “Improved 3-D Seismic Processing Techniques” Brothers Production Unsuccessful

4. “Integrated Exploration Using 3-D Seismic” Double-Eagle Enterprises Unsuccessful

5. “Telluric Surveys” Keener Oil & Gas Company Unsuccessful

Formation Evaluation

6. “Formation Micro-Imaging (FMI) Log” University of Alabama/Cobra O&G Successful

7. “Low-Invasion Unconsolidated Coring System & Core Analysis” Sandia Operating Corporation Successful

Improved Oil Recovery Successful

8. “Inert Gas Injection” Dakota Oil Producers, Inc. Successful

9. “Stimulating Formations Thermally” Diamond Exploration, Inc. Unsuccessful

10. “Microbial Improved Oil Recovery” Edmiston Oil company, Inc. Successful

11. “Closed-Loop Extraction of Hydrocarbons and Bitumen from Oil-Bearing X-TRAC Energy, Inc. Successful

Soils”

Operations

12. “Computerized Well Monitoring System” James Engineering, Inc. Successful

Production Problems

13. “Improved Stimulation” K-Stewart Petroleum Corporation Successful

14. “Resin-Coated Prepacked Gravel” Industrial Technology Management, Inc. Successful

Stimulation

15. “Foam Frac and Foam Acid Treatment” Sipple Oil Company Successful

Water Production

16. “Gel Polymer Treatment” Grace Petroleum Successful

17. “Cost Effective Water Disposal” Harry A. Spring Unsuccessful

18. “Gel Polymer” Kenneth Y. Park Successful

Wellbore Problems

19. “Oxygen Activation Log” J. R. Pounds, Inc. Unsuccessful

20. “Microbial Cleanup of Paraffin” Rock Island Service Company, Inc Successful

21. “Microbial Wellbore Cleanup” Spier Operating Company Successful

22. “Calcium Carbonate Prevention” Tenison Oil Company Successful

BACKGROUND



The Program



The “Petroleum Technology Advances Through Applied Research by Independent Oil Producers” program

was initiated by DOE/NPTO to provide small independent operators with the means to help find solutions

for their local production problems. The program, in the form of cost-sharing assistance, was aimed at

encouraging producers to apply new technologies and new and innovative concepts, ideas, and approaches

to solve their particular operational problems.



Many small independent operators lack the resources to test unfamiliar technologies or novel, unproven

approaches without cost-sharing assistance to reduce financial risk. By providing cost-sharing assistance,

DOE has attempted to encourage producers to experiment with higher risk technologies to help solve their

particular production problems. The program was primarily aimed at the use of innovative field application

of technologies to increase production and to demonstrate the benefits of the applications to other operators.



The program was initially conducted through BDM-Oklahoma, Inc., (BDM), Management and Operating

Contractor for the DOE/NPTO. Work for the program was completed under prime contract DE-AC22-

94PC91008 at the National Institute for Petroleum and Energy Research (NIPER), Bartlesville, Oklahoma.

BDM's role was that of administrator of the program; i.e., to select the projects for the program, monitor the

individual project progress, insure that the program requirements were adhered to, and to distribute the cost-

sharing funds to the project operators.



BDM, under the direction of NPTO, provided technical support to small, independent operators to increase

production. The support was to be provided by means of cost-sharing agreement subcontracts and was not to

be considered as a grant to the operators. The prospective subcontractors were required to provide a minimum

50% cost-share, including in-kind contributions. DOE's matching cost-share portion of each individual

subcontract was not to exceed $50,000.



The program was intended to encourage smaller independent operators to utilize unfamiliar and innovative

approaches to increase production, reduce operational costs, reduce environmental concerns, or develop new

technology as a way of maintaining domestic production and recovery levels. The goals and objectives of the

program were expressed as follows:



1. Extend the economic production of domestic fields, thus slowing the rate of well abandonment’s and

preserving industry infrastructure (including facilities, wells, data, and expertise).



2. Increase ultimate recovery in known fields using advanced technologies by demonstrating:



 Better methods for formation evaluation.

 More efficient oil recovery and production technologies.

 Well control and remedial work for environmental compliance.



3. Develop new technologies or improve (expand the application of) existing technologies for direct use

in new applications designed to solve existing production problems and/or reduce costs.



4. Use field demonstrations to broaden information exchange and technology application among

stakeholders by:

 Expanding participation in DOE projects to include both traditional and non-traditional

participants.

 Increasing third-party participation and interaction through the life of DOE-sponsored projects.

 Making technology transfer products user-friendly.



BDM issued a Research Opportunity Announcement (ROA), Number OKL-5027-01, soliciting proposals to

a program generally entitled "Research and Development by Small, Independent Petroleum Operators to

Provide Solutions towards Production Problems". A one-year response period between February 1, 1995,

through January 31, 1996, was allowed for the contract process. Small independent petroleum operators

were defined as; (1) operating onshore in the lower-48 states, (2) having no affiliation with a major oil or gas

producer (domestic or foreign), and (3) employing no more than 50 full time company staff or contractors.

The period of performance of a proposed project was ideally 24 months or less. Firm fixed-price cost-

sharing subcontracts were solicited.



BDM sought proposals for research and development integrating solutions to critical local production

problems experienced by small independent petroleum operators. Proposed efforts were to incorporate

innovative field technologies for use by small independents to increase production, reduce operational costs,

reduce environmental impacts or risks, or any combination of these. The types of technologies to be

considered were not limited, but could include reservoir characterization, well drilling, completion or

stimulation, environmental, compliance artificial lift, well remediation, secondary and tertiary oil recovery,

and production management.



The selection for subcontract awards was based on a scientific and engineering evaluation of the responses

(technical and price/cost) to determine the relative merit of the approach proposed in the ROA response.

New and innovative concepts, ideas, and approaches were of primary interest and were ranked highest in the

evaluation process. Proposals aimed at applying proven concepts received relatively low rankings.

Price/cost was ranked as the second order of priority in the selection process. The technical and price/cost

responses were evaluated concurrently.



A proposal was to consist of a fully completed and executed "Proposal Submission Form". The 6-page form,

provided by BDM upon request was a "fill in the blank" format. Upon request, the contractor was to provide

BDM with any or all data pertinent to the proposed project. With the assistance of BDM, the contractor was

required to submit monthly, quarterly, and annual progress reports. BDM was to provide assistance to the

contractor in the preparation of the progress reports, and BDM was responsible for preparation of a final

report for each project. To assist in preparing the final report, the contractor was required to provide BDM

with copies of daily production reports, maps of the lease, and site at which the work was to be done,

available well logs, cores and core data, well treatment history, and project pre-treatment and post-treatment

production data. An environmental investigation of the offer could be made by BDM in support of a

National Environmental Policy Act (NEPA) determination. As an integral part of the proposal, the contractor

was required to demonstrate and implement an aggressive technology transfer plan primarily targeted for

small independent petroleum operators.



The initial program was announced in February 1995 and initiated in September 1995. Over one-hundred

proposals were received and evaluated, and twenty-two projects were awarded (about one in five proposals

were approved) in nine specific technical areas; drilling, exploration, formation evaluation, improved oil

recovery, operations, production problems, stimulation, water production, and wellbore problems. The first

project was started in October 1995 and the last project was completed in April 1998. The typical project

duration was about 12 months. Out of a total program expenditure of $3.5 million, the operators contributed

a total of $2.5 million (71%) and DOE/NPTO provided $1.0 million (29 %).

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TABLE 2 (above) summarizes each subcontract and identifies the subcontractor (operator), and state of the

projects, its technical activity, start date, end date, duration, field and formation in which the project was

conducted and the financial contributions of the operator and DOE.



This Study



In January 1999, the present study was initiated by DOE/NPTO to review the twenty-two projects conducted

through the initial 1995-1998 phase. The evaluation of individual projects and the collective program was

designed to determine the direct benefits produced as a result of the program in terms of accomplishing the

intended program objectives.



In February 1999, the Support to Independents program was extended to cover a second phase of field

demonstration projects (entitled "Technology Development with Independents"). A cost-share

arrangement, similar to the initial phase, was implemented for the new work. As a part of the present study

the available material, data, and information pertaining to the initial phase of the program is being reviewed

and analyzed to determine the effectiveness of the program as well as the benefits resulting from the

program. It is intended that the results of this study will be useful in designing, managing, and

administering that second phase of the program.



The objective of this study is to evaluate the initial phase of the Program. The study seeks to assess the

extent the projects met their respective objectives and contributed to the program’s overall goals.



The analysis is to be performed through a series of tasks set out in the Scope of Work . Work completed to

date includes:





Task 1: Determine which of the 22 projects need and will benefit from future analysis.



A review of the status of the 22 projects (including collection of the information and data that are available

in contract files and various reports) was performed. This analysis determined which of the projects need

further analysis and whether adequate information exists, or can be obtained from the operators, to yield

valuable information for technology transfer and possible follow up projects. The results of this analysis

were reviewed with the project manager and the final suite of projects identified and approved for more

detailed technical and economic analysis. Results of this phase were presented to NPTO managers in April

1999.



Task 2: Perform a "lessons learned" analysis of the failed projects: e.g., i.e., determines whether the failures

result from operational problems or technology failures.



A technical review of the results of the failed projects was performed to determine, where possible, the

cause for the failure. These results have been compiled into a "Lessons-Learned" format for future reference

in managing the program. This report summarizes the findings of this task.









9

Ongoing work under this analysis includes:



Task 3: Perform an in-depth technical and economic evaluation of the projects identified in Task 1.



The technical and economic review of the successful projects identified in Task 1 is being performed to

determine if the technically successful projects were also economically successful. All of the projects that

were ostensibly successful are being evaluated to determine the level of technical and economic success.



Task 4: Prepare a detailed report and presentation materials for NPTO to assist DOE/NPTO in effectively

transferring the technology advances to the independent operators.



The detailed report will contain the results of the technical and economic analysis, the lessons learned, the

back-up data for archival purposes, and recommendations for selecting, evaluating and managing the

program. This report will serve as a final comprehensive report of the analyses completed including project

economics, technical findings, and general conclusions about the program's impact.



Task 5: Prepare a draft of trade journal article and draft summary materials suitable for posting to NPTO

and PTTC WEB sites.



The technical and economic results of the successful projects and the accomplishments of the program will

be will be prepared as a draft trade journal article (e.g., Oil & Gas Journal or American Oil & Gas Reporter)

and draft summary materials for posting to NPTO and PTTC WEB sites to publicize the results to industry.





PROJECT RESULTS –by- PROJECT





Each of the twenty-two individual projects conducted through the initial 1995-1998 phase of the Support to

Independents Program was reviewed. The degree of technical success produced as a result of the project

relative to the objectives of the program, i.e., increase production, increase reserves, develop new technology,

or advance or improve existing technology, has been, evaluated and documented. The technical review was

conduced using available and/or readily obtainable information (reports, communication with operators,

reported results, etc.) to determine the degree of success, or lack of success of each project. No attempt was

made in Task 2 to assess economics or magnitude of success beyond that expressed in the material and/or

project information available.



The review included an evaluation of each project (Task 1) to determine whether or not the project objective

and/or the program objective had been accomplished. The successful and unsuccessful projects were

identified from that evaluation, as summarized in TABLE 2, above. This section discusses and summarizes

the key findings for the eight projects identified as unsuccessful. Individual detailed evaluation fact sheets

for each of the unsuccessful projects are presented in APPENDIX A of this report. A technical review of

each of the unsuccessful projects was then performed to determine, where possible, the cause for the failure,

i.e., did the failures result from operational problems, from technical failure, or from low oil prices. These

results have been compiled into a "Lessons Learned" format for future reference in managing and

administering the ongoing Support to Independents program. A detailed discussion of the "Lessons

Learned" for each of the unsuccessful projects is presented in APPENDIX B.



A technical review of each of the unsuccessful projects was performed to determine, where possible, the

critical reasons for the failure. Four of the eight unsuccessful projects accomplished a portion of their goals

and therefore were partial successes. Projects operated by Spring, Cleary, Brothers, and Double-Eagle

generated useful results which have the potential of being successfully applied in a more applicable situation

or under more favorable oil prices.



Only four of the eight projects (operated by EDCO, Keener, Diamond, and Pounds) were unsuccessful in

producing any measurable results in terms of the program objectives of increasing production or reserves, or

even in terms of technology development or advancement. The EDOC and Keener projects, however,

suggested some promise for the future. Diamond's project produced no measurable results, but did provide

some useful operational experience and technical information that may be beneficial for further research and

development. Only one project (Pounds) produced no usable results in terms of the program benefits since

the proposed technology was not applied to solve the production problem.



Brief descriptions and summary technical review of the eight "unsuccessful" projects follows, roughly in

order of their degree of success in meeting their objectives:





Project 17. Cost Effective Water Disposal, operated by Harry A. Spring



Harry A. Spring installed a commercially available downhole simultaneous gas production/disposal tool

(DHI tool) in a watered-out shut-in Carmichael sand gas well in Logan County, Oklahoma. If produced

formation water could be economically disposed of downhole, the operator could return the well to gas



production. The DHI tool is a device allowing produced formation water to be injected into a lower

formation without first being lifted to the surface while allowing simultaneous gas production to occur.

Additionally, it was thought that dewatering of the formation near the well bore would allow higher flowing

gas rates due to more favorable relative permeability for gas.



The tool was installed in the well, but after several months of production the disposal zone pressured up and

would not take water with the existing pumping equipment. Data indicated this was caused by the limited

injection capacity of the disposal zone and by a larger volume of produced water than was originally

anticipated. The DHI tool appears to have functioned properly as proposed, but the injection capacity of the

disposal formation was inadequate for the volume of formation water being produced. The well was then

abandoned due to the high cost of conventional water disposal (hauling). The project was unsuccessful in

re-establishing gas production, although the feasibility of the technology was adequately demonstrated.

Although disappointed in the results of the project, the operator is satisfied that the technology has

additional application potential after further testing. The tool offers significant cost savings and improved

environmental compliance for underground injection control if it can be effectively applied in key, high

water rate gas wells.





Project 1. Horizontal Drilling to Increase Production, operated by Cleary Exploration LLC



Cleary Exploration LLC drilled a horizontal wellbore into a Hunton Formation low-permeability dolomitic

limestone reservoir in Pottawatomie County, Oklahoma, in an attempt to intersect additional fracture and/or

paleokarst systems to increase oil production. The horizontal section was drilled and completed open-hole as

proposed with approximately 1,400 feet of horizontal section, although serious hole stability difficulties were

encountered during drilling.





11

Initial results indicated significantly improved total fluid production from the horizontal wellbore, but the

beam pumping unit being used to produce the well was incapable of moving the amount of fluid produced by

the horizontal hole. It was estimated that the produced volumes could exceed 200 BOPD, possibly

stabilizing around 100 BOPD, if the well was equipped with high lift production equipment. However, the

first 200' of the horizontal hole collapsed before a submersible pump could be installed to fully test the

production capacity of the horizontal wellbore. It appears that the horizontal hole collapsed where the hole

had drifted up into the overlying "troublesome Woodford shale" during drilling. Attempts to clean out the

horizontal section were unsuccessful and the hole was lost before the well could be produced to capacity.

The project was unsuccessful in increasing production, however, the inconclusive results of the

demonstration do suggest the technical feasibility and do indicate significant production potential. A

sustained production test would be necessary to determine the technical and economic impact of the proposed

technology.





Project 3. Improved 3-D Seismic Processing Techniques, operated by Brothers Production Co.



Brothers Production Company used a new analytical 3-D seismic interpretation algorithm, developed to

improve time to depth conversion, to map the Ellenburger dolomite in the Fluvanna SW Field of Borden

County in West Texas. Reprocessing and reinterpretation of the existing 3-D seismic data using the new

analytical function resulted in confidently mapping of Ellenburger dolomite reflections. The reinterpretation

has identified several Ellenburger structural anomalies that were uneconomic to drill due to low oil prices at

the time. The reinterpreted 3-D seismic data indicated that the Ellenburger top in two pre-project dry hole

wells was lower than had been predicted from the original 3-D seismic data due to inherent interpretation

inaccuracies and processing artifacts of the time to depth conversions. The two dry holes would not have

been drilled had the reinterpreted 3-D seismic been available at that time.



One well was drilled to test a Wolfcamp structural anomaly, identified from the reinterpreted 3-D seismic

data. The Wolfcamp structure was present as indicated, but the formation was water-saturated. The project

is unsuccessful because no Ellenburger wells have yet been drilled to verify the definitively reinterpreted 3-

D seismic maps. Further drilling activity in the area was suspended due to unfavorable economics at the low

oil prices which existed at the time of the project and the economic uncertainty associated with production

operations. The operator does plan to integrate the mapping results into future exploitation drilling plans

when prices recover sufficiently. Several wells would need to be drilled to determine the accuracy of the

Ellenburger maps developed from the use of this technology (i.e., a statistical issue) and the final outcome of

this project is yet to be established. Nevertheless, the reinterpreted dry holes and the structural high are very

promising.





Project 4. Integrated Exploration Using 3-D Seismic, operated by Double-Eagle Enterprises, Inc.



Double-Eagle Enterprises, Inc., used 3-D seismic survey data to supplement existing 2-D seismic data to

better identify drilling prospects in the Wilcox sandstone formation in Kay County, Oklahoma. Existing

2-D seismic data did not provide sufficient information to identify the more likely productive features of the

Wilcox structure, resulting in a low exploration success rate for the area.



The 3-D seismic data interpretation on a first prospect did not support the existence of a structural anomaly

that had been indicated by the 2-D seismic data. Based on this information, the well to test the structure was

cancelled saving the cost of drilling a likely dry hole. Another well was drilled on a second prospect to test a

structural anomaly identified from the 3-D seismic data interpretation, but due to an unanticipated thickening

12

of the overlying formation, the Wilcox top was structurally flat (low) and the formation was water-saturated.

Review of the seismic data suggested that although the top of the overlying formation was structurally high, as

confirmed by drilling data, the 3-D seismic data did not suggest that the overlying formation was thickening.

Possible seismic velocity pull-up had been misinterpreted as a favorable underlying Wilcox structural high.



The project was unsuccessful because a dry hole was drilled based on the 3-D seismic data interpretation.

Further drilling activity in the area was suspended due to unfavorable economics at the low oil prices that

existed at the time of the project. Although the project results were disappointing, the experience gained from

this project and the data from 3-D seismic program may provide useful information that can be integrated into

future drilling plans. Several more wells would need to be drilled in order to determine if the success rate has

been improved by this technology (i.e., a statistical issue.





Project 2. Horizontal Drilling for Improved Wellbore Drainage, operated by EDCO Producing, Inc.



EDCO Producing, Inc., attempted to drill a horizontal wellbore in an energy-depleted compartmentalized

reservoir to try to intersect possible accumulations of trapped oil in the Trempealeau Formation in Morrow

County, Ohio. Drilling of the horizontal hole was suspended approximately 30 feet into the lateral turn

section because of severe hole problems and the extreme difficulty in stabilizing hole direction. The

fractured dolomite formation being drilled began to crumble and slough into the borehole, and the drilling

assembly became stuck and had to be fished out. Based on the inability of the wellbore to stay on course

and the corkscrew form of the drilling effort, in conjunction with the formation hole problems, the

horizontal drilling attempt was suspended far short of the 300-600 ft. of horizontal section originally

planned.



The project was unsuccessful because the proposed technology could not be successfully applied in the

proposed formation and oil production rates were not improved due to the limited length of the lateral

achieved. Although the operator expressed an interest in conducting additional drilling efforts, none are

currently planned due to poor project economics given the low oil prices at the time of the project. The

feasibility of horizontal drilling in this formation remains to be adequately demonstrated and certainly the

concept of increasing production rates by intersecting compartmentalized, trapped oil with a vertical

borehole remains undemonstrated.





Project 5. Telluric Surveys, operated by Keener Oil & Gas Co.



Keener Oil & Gas Company used an electrotelluric (telluric) survey as a tool to try to define subsurface oil and

gas bearing structural traps in the Wilcox Sand of Creek County, Oklahoma. An electrotelluric survey is a

measurement of the resonance signal created when atmospheric generated electromagnetic pulses penetrate the

earth's surface, creating a secondary electrical field that propagates downward and ultimately resonates from

subsurface beds of contrasting resistivities.



A well was drilled to test a subsurface structural anomaly identified through the telluric survey data

interpretation, but the target formation was not on structure and was dry. The target formation was 22 feet

lower than indicated by the telluric interpretation. Review indicated that formation tops and target zones

predicted by the telluric data were either undefinable or shallower than the actual depth encountered by the

drilled well. The project was unsuccessful because the survey interpretation results were not accurate enough

to give reliable results.



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The technology concept used in the project appears feasible, but is still in an early developmental phase.

Further testing of this technology by the operator has been temporarily suspended due to the unfavorable

economics of development drilling at the low oil prices during the project. The proposed technology has

significant application potential if it can be adequately developed. Costs for Telluric surveys are considerably

less than for a seismic surveys and, leave little if any environmental impact. Telluric surveys certainly warrant

further research and development.





Project 9. Stimulating Formations Thermally, operated by Diamond Exploration, Inc.



Diamond Exploration, Inc., used high-voltage electrical current to generate heat in the small, heterogeneous,

shallow Cottage Groove sand of the Paola-Rantou-Shoestring Field in Miami County, Kansas. The project

attempted to improve heavy (low gravity) oil recovery. Copper probes were placed at the formation in each

of three wells in a triangular pattern approximately 100 feet apart with a producing well in the center. The

probes were energized by an electrical current over a period of six days. The reservoir temperature at the

probe wells was elevated from 58oF to 101oF and a small, non-commercial quantity of 21oAPI gravity

viscous oil was recovered from one of the probe wells. Inert gas was injected into each of the probe wells

after the formation was heated and pressure communication was immediately established with the producing

well. However, the formation temperature at the producing well did not increased and no oil was recovered

from the producing well.



The project was unsuccessful because the technology applied did not result in any oil production. Although

the operator remains optimistic about the potential of this technology, it is still in an early experimental

stage and the technical and economic feasibility of the process must be clearly demonstrated.





Project 19. Oxygen Activation Log, operated by J. R. Pounds, Inc.



J. R. Pounds Inc., proposed to use an Oxygen Activation Log to locate holes in casing for repair as a way of

reducing costs in the Rodessa Sand of the Bolton Field in Hinds County, Mississippi. During initial

investigation by the operator, a logging service company advised that the Oxygen Activation Log was not

designed for casing hole detection in the particular situation that existed in the target well. The target well

was on rod pump, shut-in, and not flowing. The logging tool requires the flow of water past the tool in order

to function. Conventional bridge-plug and packer pressure testing methods were then employed to locate

the casing holes and conventional casing leak repair methods were used to successfully repair the leaks. The

production problem was solved and the well was put back on production using conventionally available

(non-R&D type) technology to solve and correct the problem. No technology experiment was conducted.



The project failed to meet the requirements of the program because the proposed technology was not

applicable to the situation and was thus not applied. No conclusions about the technical or economic results

can be drawn from this project. Repair of leaking casing is a critical production and environmental concern

for operators. Future testing of this method could be justified if appropriate settings can be identified.



DISCUSSION OF RESULTS





Several reasons contribute to the lack of success of these eight projects, including:



 Application failure

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 Inappropriate technology application

 Unfavorable economics due to the low oil prices

 Poorly developed technology

 Inadequate project planning.



All five of the projects in the areas of Exploration and Drilling (Cleary, Brothers, Double-Eagle, EDCO, and

Keener) were unsuccessful in accomplishing the objectives of the program. Four of the five projects

(Cleary, Brothers, Double-Eagle, and EDCO) used well-developed technologies (horizontal drilling and 3-D

seismic), although Brothers also incorporated a new interpretation technique. The fifth project (Keener)

attempted to apply the relatively new and untested technology of Telluric surveys. All five of these projects

were attempted in unique settings (new areas/fields/formations) under difficult situations (complex

formations hard to identify from seismic data or difficult formations to drill, etc.). None of these five

projects have been pursued further because of unfavorable project economics due to recent low oil prices.



Both of the 3-D seismic projects (Brothers and Double-Eagle) were well-designed using well developed and

widely applied technologies, but both attempted applications that are inherently high risk. The technologies

applied in both projects hold significant potential. These "unsuccessful" projects have provided additional

information needed to improve the confidence level and thus reduced the inherent risk involved in all

geophysical exploration and drilling activities.





Both of the horizontal drilling projects (Cleary and EDCO) also used well-developed and widely applied

technologies, but both projects were under-designed considering the high degree of risk with an unfamiliar

technology in a new area (field) and the lack of experience. And again, both attempted applications were

inherently high risk.



Two of the other unsuccessful projects (Keener and Diamond) utilized very unconventional and essentially

previously undemonstrated technology (tellurics and in-situ electrical heat generation). Both processes are

currently poorly understood and high risk due to their experimental nature. The telluric project (Keener)

was about as well designed as could be expected considering the current state of technology development.

The thermal project (Diamond) was not well designed resulting in somewhat of a trial-and-error type field

experiment.



The remaining two projects (Spring and Pounds) were unsuccessful because of poor pre-project evaluation

which would have indicated that neither project was feasible under the particular existing conditions.

Spring's DHI tool project needed a better pre-project engineering evaluation (i.e., a definitive injectivity test

of the target disposal zone, etc.). The project demonstrated that the technology worked as designed, even

though the application was unsuccessful, and that the technology has the potential of being successfully

applied in a more applicable situation. Pound's Oxygen Activation Log project was not well planned at all,

it simply needed a better pre-proposal review (i.e., a phone call to the service company).



Two of the projects (Brothers and Double-Eagle), although identified as unsuccessful as far as the project

review is concerned, have not as yet been fully tested or demonstrated and thus are actually inconclusive at

this point. Both of these projects were prematurely suspended when drilling activities were postponed due

to low oil prices and unfavorable project economics. Each of these projects will require additional field-test

applications before it can be determined conclusively whether they are viable and can consistently improve

drilling success rates.





15

A third project (Cleary), also identified as unsuccessful indicated sufficient potential success (even though

sustained demonstration of the project was unsuccessful) to warrant additional testing. Additional

applications are needed to determine conclusively if the technology and application concept could be

successful with a different drilling and/or completion program. The operator of this project could not be

contacted to clarify key questions. This project will be further evaluated during Task 3 using whatever

information is available to complete project economic evaluation.



Four of the projects were completely unsuccessful in producing any measurable, tangible, or quantifiable

results (EDCO, Keener, Diamond, and Pounds). The proposed technology for EDCO's project was not

demonstrated because the horizontal section could not be completed to even test whether or not oil recovery

could be improved. Keener's project resulted in drilling a dry hole because the telluric survey results were

inaccurate and unreliable. The Diamond project generated heated in the formation but produced no oil

(possibly due to low oil saturation). Pounds proposed technology that was not applicable to the problem and

thus was not utilized.



All eight of the unsuccessful projects consisted of reasonable proposals (although, the project by Pounds

should have been evaluated by the operator before it was proposed). All involved small independent

operators applying unfamiliar technologies and practices to solve existing production problems. All of the

projects clearly qualified for inclusion in the Support to Independents program.





Many of the project operations (successful and unsuccessful) were suspended due to unfavorable economics

as oil prices decreased to decade lows near the end of the project demonstration period. Even though the

economic situation has improved significantly as oil prices have recovered during mid-1999, most of the

operators remain cautious about continuing or re-starting their projects. Several of the operators of the

successful projects have indicated plans for continuation and/or expansion (with and/or without

modification) when and if economics improve. Several of the successful technologies have wide application

potential under improved economic conditions. All of the operators contacted indicated that they would like

to continue to utilize or further experiment with the technology if oil prices recover sufficiently. Even the

operators of the partially successful and unsuccessful projects indicated that they would like to make

modifications to their projects and reapply the technology using the experience gained during the DOE

sponsored test, if oil prices maintain relatively high levels. Only one project (Pounds) expressed no interest

in further application of the technology, although the assistance they received was critical to returning their

well to production.



Many of these projects were just concepts that operators developed into working practices based on their

experience. The Support to Independents program provided the opportunity to design, implement, test, and

revise these processes in a field environment. Even though some tests were unsuccessful, nearly all

generated valuable data and direct experience. Small independent operators have very limited staff and

financial resources with which to conduct their own in-depth detailed engineering, geological, geophysical,

and/or project design studies, and most have little or no access to laboratory R&D facilities. These factors

are critical to increasing the chance for success for specific processes or practices. Usually, their only

recourse is to just "try it and see what happens" based on their own experiences and/or knowledge (and most

of these small independent operators are very innovative and resourceful at “keeping their wells pumping”

and at cutting costs to stay in business). They draw on the experience of other operators, relying heavily on

assistance from service companies, contracting with engineering, geological, geophysical consultants and

often with college professors and any other available means, to try to get the job done as best they can.

These projects were conducted by operators of adventurous nature, used to risk taking, and in most cases



16

rather desperate for economic solutions to their production problems, and so ventured forth anyway despite

the risks involved and the odds against them, hoping for the best.



Although the eight unsuccessful projects did not result in an increase in production or reserves or in successful

development of new technology these projects contributed significantly to the experience and knowledge base

of the technology represented and to the future development and/or application of that technology. Thus,

these projects were extremely valuable in terms of intangible achievements and contributions. Those

operators who allocated capital to attempt these projects should be acknowledged for their contribution and

for the risks they were willing to undertake; that risk having been reduced considerably by the Support to

Independents cost-sharing assistance program.





CONCLUSIONS AND RECOMMENDATIONS





The selection and implementation of the first phase of Support for Independents was highly effective in

funding meaningful, and generally successful, projects. The program achieved its primary goal of identifying,

developing, and demonstrating technologies that could be employed by small independent operators. The

relatively large number of fully successful research projects indicates an effective program and willingness by

operators to be flexible and to adjust to changing conditions.



The eight projects that were determined to be unsuccessful in terms of meeting program objectives were

generally partially successful in testing key concepts. Seven of these projects generated critical application

information and results that can be used to better understand, further develop, or expand the use of the tested

process. Often research "failures" provide more valuable information than do successes. It is important that

thorough documentation and evaluations of these projects be maintained. Their results should also be

published to aid other operators in designing and implementing similar projects.



The unsuccessful projects would have benefited from additional technical input and review during the test

period. The program did not provide direct technical assistance during the contract period. Operational

difficulties encountered by some operators could have been overcome, in some cases, if direct access to

engineering, geology, and laboratory assets were available. A multi-disciplinary team of advisors with limited

access to labs and service companies could have advised operators on alternative approaches. Further,

uniform technical assistance across all projects would have enhanced the consistency of research methods and

increased the impact of individual projects and the entire program.



Additional documentation of the results of projects could aid in documentation and research and development

follow-up critical to technology transfer and focusing future research efforts. Closer monitoring of progress

during the project and a more comprehensive, consistent, and required reporting process would have enhanced

the impact of research results. Although internal guidelines of the program attempted to simplify and

minimize paperwork, some key reports lacked technical data needed for further evaluations. Standardized

documentation, including the development of a Final Report Form, could assist in compliance and consistency

of reporting without being overly burdensome.



Technology transfer to other independents is critical to ultimate success of the program. Under the 1995-1998

version of the program, the funded operators were expected to be the primary technology transfer agents. Two

factors inhibited the effectiveness of this approach. First, the desire to minimize the paperwork burden on

busy operators can limit the amount of information sought by the program. Second, independent operators

may lack the skills, experience, and/or willingness to prepare and present their results effectively. Outside

17

third–parties already engaged in technology transfer (e.g., the regional offices of the Petroleum Technology

Transfer Council), if provided with the full data from the projects, might be more effective in transferring the

technology tested and demonstrated in this program.



Low oil prices dramatically impacted the research activities in the initial phase. Given the historic volatility of

oil prices, NPTO should consider the impact that changes in oil price, up or down, could have on future

research efforts. Given that most of the projects undertaken had marginal project economics, changing oil

prices can, and did during the initial phase, cause operators to revise their projects in ways that can reduce

their technical value. Clearly, the program must be sensitive to the changes in project economics attendant to

changes in oil prices and the risks they can impose on operators. However, the program needs also to attain a

minimum return of performance and data from each project. Perhaps it would be useful to agree upon a

minimal project execution (perhaps well less than the full design) that would be completed even if oil prices

were to fall dramatically. Such negotiations could be included in the final stages of contracting.



The following recommendations are offered as a result of the project specific evaluations completed based on

review, analysis, and evaluation of the eight unsuccessful projects involved in the initial 1995-1998 phase of

the Support to Independents program.



1) The project entitled "Cost Effective Water Disposal" operated by Harry A. Spring should be referred

to the DOE Federal Energy Technology Center gas program or to the Environmental Program, because

the technology only applies to natural gas wells producing large volumes of water. Environmental

compliance in sensitive areas, particularly those with fresh water aquifer concerns, may be a primary

utilization for this process. Even though the application was unsuccessful, the technology appears to

have functioned as designed and has significant application potential.



2) The project entitled "Horizontal Drilling to Increase Production" operated by Cleary Exploration,

LLC will be further evaluated in Task 3 to determine the economic impact of the project and to attempt

to obtain enough information for possible technology transfer application. Although the project was

abandoned before a sustained production test could be established, the inconclusive results suggest the

feasibility of the technology and indicate significant production potential.



3) Both of the 3-D seismic projects, "Improved 3-D Seismic Processing Techniques" operated by

Brothers Production Company and "Integrated Exploration Using 3-D Seismic" operated by Double-

Eagle Enterprises, should be reviewed periodically to determine their final outcome. Both projects were

suspended prematurely before the eventual results could be adequately demonstrated. If drilling activity

resumes and the technology proves to be successful for either of the projects, then the project results

should be integrated into the technology transfer program. The operators should be asked to assist, but

not expected to comply without compensation.





4) Even though the results "Telluric Surveys" project, operated by Keener Oil & Gas Company, were

unsuccessful, tellurics as a subsurface exploration tool has significant cost savings and environmental

mitigation potential. Research on this technology should be encouraged through the appropriate

forum(s), to determine if telluric intrepretation can be developed sufficiently to provide reliable results.



Although the eight projects discussed in this report were unsuccessful, the results generated contributed to a

substantial improvement the process being tested or its field application requirements. One or more of these

will be further evaluated to measure economic impacts of their testing. All of the technologies tested in the

initial phase hold future promise for solving key problems facing independent operators. With additional

18

clarification of goals, improved documentation, and aggressive technology transfer, additional research in

this area should be extremely valuable, aiding domestic operators, an hence the country as a whole.









19

APPENDIX A



EVALUATION FACT SHEETS





This section consists of evaluation fact sheets describing each of the projects that were less

than fully successful. They are (sorted by the relative degree of success, most successful

first), providing details about the problem, setting, project, and results:



Project 17. Cost Effective Water Disposal, Harry A. Spring



Project 1. Horizontal Drilling to Increase Production, Cleary Exploration LLC



Project 3. Improved 3-D Seismic Processing Techniques, Brothers Production Company



Project 4. Integrated Exploration Using 3-D Seismic, Double-Eagle Enterprises



Project 2. Horizontal Drilling for Improved Wellbore Drainage, EDCO Oil Company



Project 5. Telluric Surveys, Keener Oil & Gas Company



Project 9. Stimulating Formations Thermally, Diamond Exploration



Project 19. Oxygen Activation Log, J. R. Pounds









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Project 17. Cost Effective Water Disposal, Harry A. Spring





Problem Gas well making so much water that conventional water disposal became cost prohibitive and the well was

shut-in.

Proposed Solution Install a down hole simultaneous gas production/disposal tool (DHI tool) to produce gas and economically

& Technical dispose of produced formation water into a deeper formation without first being brought to the surface.

Description Dewatering of the formation near the well bore will allow higher flowing gas rates.

Reservoir Setting Gas well producing from the Carmichael Sand @ 3,123 ft., in Logan County, Oklahoma, making too much

& Information water to economically dispose of conventionally (by hauling). Initial gas production was 1,017 mcfd but after

18 months of production, the well was producing 448 mcfd and 120 BWPD. Water hauling became cost

prohibitive and the well was shut-in. The high cost of water disposal will result in premature abandonment of

the well leaving significant gas reserves in the ground.

Objective/intent Program Objective: Increase production and reserves.

Project Objective: Install a down hole simultaneous gas production/disposal tool (DHI tool) to produce gas

and economically dispose of produced formation water into a deeper formation.

Working Use new technology vs. leave well shut-in due to high cost of water disposal at the surface.

Hypothesis

Baseline & Prior to the project, production before the well was shut-in was 448 mcfd gas and 120 BWPD. Forecast

Forecast returning well to production at 600 MCFPD gas and zero water.

Compare: Unable to maintain injection after applying technology. Initially, the well produced 30-40 mcfd and the DHI

Actual vs baseline tool was disposing of approximately 300 BWPD with the fluid level at 1,500 ft. The well was producing

more water than had been anticipated. After 18 months, the injection interval pressured up to 2,091 psi and

quit taking water. The well was abandoned at that time.

Economic? No data to run economics. The project AFE was $55,000 including $14,500 for the DHI tool.

Economics included in the project proposal indicated a 13 month pay-out for the installation costs.

Project Objective The project objective was not met. Although the DHI Tool appears to have performed as designed, the

Met? disposal formation was incapable of taking the volume of water produced by the well and the producing

formation did not dewater as intended.

Program Objective The program objective was not met. The pre-project gas production was not re-established. The well was

Met? abandoned without increasing production or adding reserves.

Lessons Learned Adequate disposal zone injection capacity must be available for the volume of water produced.



Application The technology has world-wide application for use in gas wells producing only gas and water. The

(area/region) technology allows the disposal of produced water without first being brought to the surface, thus reducing

disposal costs and reducing the risk of contamination of the surface environment.

Limitations The technology applied is limited to use in gas wells producing only gas and water, and which have a deeper

disposal zone with sufficient injection capacity. The DHI tool requires a beam pumping unit with a rod string

and sinker bars.

Recommendations This was a gas production project and thus beyond the scope of the NPTO program. This project should be

referred to the DOE Federal Energy Technology Center gas program.









21

Project 1. Horizontal Drilling to Increase Production, Cleary Exploration LLC





Problem: Production rates and ultimate recovery vary widely from one well to another and production from new wells is

often marginal to non-commercial. The inconsistent and unpredictable results appears to be due to the specific

reservoir fracture and/or karst system intersepcted (or not intersected) by the vertical wellbore.

Proposed Solution Re-enter an existing vertical well and drill a 1,500 foot horizontal section through the formation to intersect the

& Technical maximum number of potentially productive fractures. The horizontal wellbore will expose more formation

Description: face to the wellbore and extend the effective drainage area of the well.

Reservoir Setting The Hunton Formation in Pottawatomie and Oklahoma Counties, Oklahoma, is a dolomitic fractured limestone

& Information: occurring at about 5,100 ft. and in this area is a thick carbonate section, generally fractured, normally

pressured, and productive of both oil and water with minimal gas production. The zone is known to be very

prolific in areas of adequate porosity and permeability development, explained by the possible presence of

localized areas of extensive fracturing, erosion, and re-working resulting from tectonic folding, and identified

as karst zones.

Objective/Intent: Program Objective: Increase production and reserves.

Project Objective: Test the feasibility and economics of drilling a horizontal well through the oil zone of the

fractured limestone reservoir to encounter additional fracture or karst systems to increase production.

Working Drill a horizontal well to accelerate the production of reserves vs continue marginal production from the

Hypothesis: vertical wellbore to the economic limit and then shut-in and abandon the well.

Baseline & The vertical well, drilled and completed in 1996, originally tested 10 BOPD and 70 BWPD. No production

Forecast: forecast was presented.

Compare A beam pumping unit was set and the well placed on production with a conventional rod pump set as low in

Actual vs baseline: the build section as the curvature would allow. Initial fluid production from the horizontal section increased

approximately 6 fold with fluid level at around 2,000 foot and the well was not pumped-off with the existing

rod pump. It was believed that production volumes could have reached 200 BOPD, possibly stabilizing

around 100 BOPD, if the well were equipped with high-lift equipment. The horizontal hole collapsed shutting

off production before a submersible pump could be run to produce the well to capacity. After the hole

collapsed, production rates quickly dropped and the working fluid level fell to the rod pump intake.

Economic? No economics to run. Results are inconclusive because production was interrupted, but indications are that

production could have been significant and that the well would probably have been economic had production

continued. The project AFE was for $295,000 for a completed producer (including $75,000 for vertical

reentry, $90,000 to drill horizontal lateral, and $130,000 for completion, set pumping unit, and equip to

produce). The modified AFE was for $250,000 for reentry and drilling the horizontal lateral w/a drlg rig.

Project Objective The project objective was not met. The well was drilled and completed open hole as proposed with

Met? approximately 1,400 foot of horizontal section. Initial production was interrupted approximately 3 days after

production start-up when the horizontal hole collapsed where the hole had drifted up into the overlying

Woodford shale during drilling. Attempts to clean out the obstruction were unsuccessful and the borehole was

lost.

Program Objective The program objective was not met. No additional oil was produced and no additional reserves were added.

Met? However, the inconclusive results of the demonstration do suggest the technical feasibility and do indicate

significant production potential.

Lessons Learned Inability to maintain hole stability during drilling of the horizontal section probably created the conditions

which resulted in the hole collapsing. Setting a liner in the horizontal section might have protected the hole.

Application The potentially productive fractured Hunton Limestone formation underlies an estimated 200 square miles of

(area/region) several counties in central Oklahoma. If successfully demonstrated, the technology would have wide aerial

application with significant production potential.

Limitations There are few limitations to the technology other than the incremental production volumes which must be high

enough to justify the additional cost and risk of horizontal drilling. Horizontal drilling technology is well

developed and has been applied successfully in other similar applications.

Recommendations Additional horizontal drilling should be encouraged in this area, using improved horizontal drilling and

completion technology in conjunction with the experience gained in this attempt, to fully determine the

feasibility of this technology application. A sustained production test is necessary to determine whether or not

production can be improved in this field by the proposed technology.









22

Project 3. Improved 3-D Seismic Processing Techniques, Brothers Production Company





Problem Ellenburger dolomite infill drilling prospects are difficult to identify because the formation top cannot be

accurately mapped by conventional 3-D seismic interpretation due to incorrect time to depth conversion of

seismic horizons.



Proposed Solution Use an integrated interpretation of existing log and 3-D seismic data to conduct a velocity analysis using new

& Technical analytical equations to predict time to depth conversions. Generate structural maps to identify structural

Description anomalies for exploitation prospects and drill a well to test the accuracy of the integrated re-interpretation

technique.

Reservoir Setting Conventional 3-D seismic survey data was acquired and utilized in an attempt to identify Ellenburger

& Information dolomite structural highs between existing development wells for infill drilling prospects in the Fluvanna SW

Strawn Unit in northeastern Borden County, Texas. Using conventional 3-D seismic interpretation, two dry

holes were drilled into the Ellenburger dolomite @ 8,400 ft. The error in the existing time to depth

conversion technique was severe enough that additional wells would not be drilled unless the technology

could be developed to improve the conversion process significantly.

Objective/intent Program Objective: Increase reserves.

Project Objective: Reinterpret the existing 3-D seismic data using analytical functions to improve the time to

depth conversions, generate structural maps of objective exploitation prospects, then drill a well to test the

accuracy of the technology.

Working Reinterpret 3-D seismic data using new analytical functions to improve the velocity conversion to an accuracy

Hypothesis which will reduce the risk in drilling exploitation prospects vs. suspending all infill drilling activities in the

prospect area due to low success rate.

Baseline & Based on conventional 3-D seismic interpretation, two pre-project dry holes were drilled in the prospect area

Forecast and future drilling activities were suspended. Successful wells were predicted to produce 41.4 BOPD & 21

MCFD. 5 successful exploitation prospects could add an estimated 1.5 MMBO reserves to the project area.

Compare: No Ellenburger wells were drilled based on the reinterpreted 3-D seismic data (due to low oil prices at that

Actual vs baseline time). One Wolfcamp dry hole was drilled based on the 3-D seismic reinterpretation. Based on drilling

information, that well was successfully completed in the shallower Spraberry formation and 150,000-200,000

barrels of new oil reserves were developed.

Economic? There is no data with which to run economics on the project. The well drilled did not result in production

from the Ellenburger formation. The AFE for drilling and completing the proposed Ellenburger well was for

$264,000 dry hole and $450,000 completed.

Project Objective The project objective was not met. The reinterpreted 3-D seismic data has identified several Ellenburger

Met? structural anomalies, but none of those have yet been drilled. The operator is of the opinion that the quality

of the Ellenburger structural mapping was improved significantly by the reinterpreted 3-D seismic data and

that the overall drilling success rate will be increased. The operator plans to integrate the mapping results

into their future Ellenburger exploitation plans.

Program Objective The program objective was not met. As of yet, no additional Ellenburger production has resulted and no

Met? additional Ellenburger reserves have been developed by the project.

Lessons Learned Final results have not yet been determined. Development drilling activities have been suspended until the

economics improve sufficiently. The quality of the Ellenburger structural map may have been improved by

the reinterpreted data, but several wells will need to be drilled in order to determine if the drilling success rate

can be improved. An improvement in the overall drilling success rate requires the drilling of at least as many

wells as were utilized in determining the baseline success rate (i.e., a matter of statistics).

Application The technology developed, if successfully demonstrated, has wide application to the Ellenburger formation

(area/region) throughout the Easter Shelf of the Permian Basin area. With the improved confidence from the reinterpreted

3-D seismic data and the experience gained, the operator plans to utilize the technology in future in-fill

drilling activities in the Fluvanna SW Field, when drilling activities resume.

Limitations The technology has yet to be successfully demonstrated. Additional drilling will be required to determine if

the re-interpretation does improve the overall success rate.

Recommendations This project should be reviewed periodically to evaluate the final results of any future drilling activities in

order to determine whether or not the technology proves to be successful.









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Project 4. Integrated Exploration Using 3-D Seismic, Double-Eagle Enterprises





Problem The success rate for Wilcox Sand discoveries in Northern Kay County, Oklahoma, using existing exploration

technology is well below 10%. Currently, only subsurface and either single fold or 2-D seismic data are

available.

Proposed Solution Acquire and integrate 3-D seismic data and surface geo-microbial recon techniques (the microbial survey was

& Technical later dropped from the revised project plan due to budget constraints) into existing exploration program to

Description improve the discovery success rate. Drill 2-3 of the potential prospects to determine the accuracy of the

technology.

Reservoir Setting Only subsurface and either single fold or 2-D seismic data have been used for exploration in the shallow,

& Information 4,000 ft. Wilcox sands of Northern Kay County, Oklahoma. The shallow Wilcox structures are small in a real

extent, usually less than 100 acres, and not economically attractive for large regional 3-D seismic surveys.

Objective/intent Program Objective: Increase reserves.

Project Objective: Incorporate 3-D seismic techniques into existing exploration program to improve the

discovery success rate in the drilling of 2 to 3 Wilcox sand wells in the prospect area.

Working Use 3-D seismic data to improve the exploration success rate vs. continue to use 2-D seismic data which has

Hypothesis an exploration success rate of less than 10 %.

Baseline & Previous exploration drilling success rate was less than 10 %. Forecast was that the success rate could be

Forecast improved to 25 % or more utilizing 3-D seismic data. Successful Wilcox sand wells exceed 100,000 BO

reserves.

Compare: A Wilcox sand was drilled to test a structural high indicated by the 3-D seismic data, but the structure was

Actual vs baseline lower than indicated and the well was a dry hole. The Wilcox sand drilling success rate was not improved

using the reinterpreted 3-D seismic data for the well drilled. Further drilling activity was suspended (due to

low oil prices at that time). Based on the 3-D seismic data, the second prospect was not drilled.

Economic? No data was generated with which to run economics. The Wilcox well drilled was dry, thus there was no

production. All cost of the project, including the drilling of the well, was lost. The AFE for drilling and

completing the well was $65,250 dry hole cost and $113,250 for a completed producer.

Project Objective The project objective was not met. Drilled one dry hole based on the 3-D seismic interpretation. A second

Met? prospect, identified from 2-D seismic data, was not confirmed by the 3-D seismic data and thus was not

drilled. The operator identified several conditions which may have led to a misinterpretation of the data.

The operator is of the opinion that the 3-D seismic data will improve the drilling success rate overall when

drilling activity resumes.

Program Objective The program objective was not met. As of yet, no increased production has resulted from the project and no

Met? additional reserves have been developed.

Lessons Learned The final results have not yet been determined. Drilling activities have been suspended until the economics

improve sufficiently. Several wells will need to be drilled in order to determine if the drilling success rate can

be improved. An improvement in the overall drilling success rate requires the drilling of at least as many

wells as were utilized in determining the baseline success rate (i.e., a matter of statistics).

Application The technology, if successfully demonstrated, has wide application throughout the area. With the improved

(area/region) confidence from the 3-D seismic data and the experience gained, the operator plans to utilize the technology

in future exploration drilling activities in the Wilcox sand, when drilling activities resume.

Limitations The technology has yet to be successfully demonstrated. Additional drilling will be required to determine if

the 3-D seismic interpretation does improve the overall success rate.

Recommendations This project should be reviewed periodically to evaluate the final results of any future drilling activities in

order to determine whether or not the technology proves to be successful.









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Project 2. Horizontal Drilling for Improved Wellbore Drainage, EDCO Producing Company





Problem Limited oil recovery due to low reservoir pressure in a heterogeneous, and possibly compartmentalized,

fractured dolomite reservoir.

Proposed Solution Drill a short radius 300-600 ft horizontal well section from an existing vertical wellbore to intersect isolated,

& Technical undepleted oil accumulations and provide a conduit for the low energy oil to migrate to the vertical well-bore.

Description Due to the low reservoir pressure, it will be necessary to drill with air and a short radius curve section will be

required to set the rod pump as low as possible in order to reach the low producing fluid level.

Reservoir Setting Limited oil recovery from the Cambrian dolomite Trempealeau Formation @ 3,088 ft. in Morrow County,

& Information Ohio, due to low reservoir pressure and possible formation compartmentalization. Numerous wells were

drilled during early development and the reservoir pressure was prematurely depleted possibly leaving a lot of

oil still in place.

Objective/intent Program Objective: Increase production and reserves.

Project Objective: Drill a short radius 300-600 ft horizontal well section from an existing vertical wellbore in

a mature, pressure depleted, possibly compartmentalized reservoir to increase oil recovery.

Working Drill a horizontal wellbore to encounter compartmentalized oil and increase oil production rates vs. continued

Hypothesis low oil production to the economic limit then shut well in and abandon prematurely, leaving significant oil in

place.

Baseline & Prior to the project, the well was producing 6 BOPD and 12 BWPD. Estimated incremental production

Forecast increase was 16.6 BOPD and 33.3 BWPD. No incremental forecast was presented. No increased operating

costs were anticipated.

Compare: Results were inconclusive because the horizontal section was not completed due to drilling problems, thus

Actual vs baseline there was no production data generated for the proposed horizontal wellbore. Seven weeks after the project,

the well was pumped-off, producing 2 BOPD and 7 BSWPD. The operator then ran a coiled tubing anchor

with check-valve below the rod pump into the curved section. Well production stabilized at pre-project rate

of 5 BOPD and 15 BSWPD. The well was then shut-in due to low economics.

Economic? There are no economics to run. There was no production data generated for the proposed horizontal

wellbore. The original project AFE for the horizontal recompletion was for $78,000 (without contingency)

for approximately a 16.6 BOPD incremental increase, with no increase in op. costs. The actual cost of

$93,423.37 included $39,000 for a drilling rig vs. $7,000 for a service rig to drill the horizontal section.

Project Objective The project objective was not met. Approximately 32 ft. into the curved section, the fractured dolomite

Met? formation began to crumble, sticking the drilling assembly which had to be fished out. Based on the inability

of the wellbore to stay on course and the corkscrew of the wellbore, the horizontal drilling attempt was

suspended. The objective of increasing production with a horizontal wellbore was not investigated.

Program Objective The program objective was not met. No incremental oil was produced and there was no increase in reserves.

Met? Due to drilling problems encountered during the early stages of drilling, the horizontal section was not

completed.

Lessons Learned Horizontal drilling in this formation appears to be exceedingly difficult and several drilling problems would

need to be addressed before another attempt could be reasonably made.

Application Horizontal drilling, when successfully demonstrated, has extensive application in fractured or

(area/region) compartmentalized formations. A successful horizontal well completion and a sustained production test

would be necessary to determine whether or not production can be improved in this field by the proposed

technology. It is yet to be determined if (1) horizontal drilling in this formation can be successfully applied

even with modifications to the drilling program and (2) production can be improved at all by a horizontal

wellbore.

Limitations Even if horizontal drilling was successful and production was improved, the technology application would be

limited by the low incremental production potential due to the low reservoir pressures. Also, the problem of

production from the horizontal section with low fluid levels would need to be solved. The low production

potential makes the use of downhole submersible pumps cost prohibitive.

Recommendations Due to the low production potential, and marginal economics of horizontal drilling in this field, horizontal

drilling activities do not appear to be economically practical. Horizontal drilling activities in this area should

not be pursued further at this time. Even if resumed at some time in the future, the drilling program will

require extensive redesign due to the difficulties that were encountered.









25

Project 5. Telluric Surveys, Keener Oil & Gas Company





Problem A telluric survey indicated a Wilcox sandstone structural anomaly not previously indicated by any other data

available. An electrotelluric (telluric) survey is a measurement of the resonance signal created when

atmospheric generated electromagnetic pulses penetrate the earth's surface, creating a secondary electrical

field which propagates downward and ultimately resonates from subsurface beds of contrasting resistivities.

Proposed Solution Drill a well to test the capability of tellurics as an additional tool to define subsurface features for exploratory

& Technical and development drilling by comparing structural tops in the drilled well with structural tops interpreted from

Description a telluric survey.

Reservoir Setting A Wilcox Sandstone subsurface structural anomaly was identified in Creek County, Oklahoma, from a telluric

& Information geophysical survey. There was no other subsurface data from the immediate area to confirm the telluric

interpretation.

Objective/intent Program Objective: Develop new technology.

Project Objective: Drill a well to test the capability of tellurics as an additional tool to define subsurface

features for exploratory and development drilling by comparing structural tops in the drilled well with

structural tops interpreted from a telluric survey.

Working Use Telluric survey data to reduce cost, risk and better define structural control where seismic data cannot be

Hypothesis acquired for exploration and development drilling vs. acquire sometimes cost-prohibitive seismic data or

utilize other high risk techniques.

Baseline & A previously undetected Wilcox sandstone formation structural anomaly was interpreted from a telluric

Forecast survey. 50-100 BOPD expected from a successful Wilcox well completion.

Compare: Wilcox sand drilling success rate was not improved using the telluric data for the well drilled. The operators

Actual vs baseline are of the opinion that telluric data can be used to improve the drilling success rate overall, but will not

eliminate the risk completely, and certainly requires additional technical development.

Economic? There was no production generated by this project with which to run economics. The Wilcox sandstone well

drilled was dry, thus all cost of the project, including the drilling of the well, was lost. The AFE for the well

was $87,675 dry hole and $191,213 completed as a producer.

Project Objective The project objective was not met. A dry hole was drilled based on telluric survey interpretation. The

Met? telluric data interpretation accuracy was not sufficient or definitive enough to provide reliable data.

Program Objective The program objective was not met because no oil was produced and reserves were not increased. There was

Met? some experience gained and information added to the knowledge base, but the state of technology

development was not improved appreciably.

Lessons Learned The technology used in this project is in a very early stage of research and development.

Application Technology if successfully developed has wide application throughout the world. Telluric surveys are a

(area/region) fraction of the cost of seismic surveys and are completely non-invasive (i.e., environmentally friendly).

Limitations If adequately developed and demonstrated, telluric data interpretation could have world-wide application.

Telluric data interpretation would not eliminate the risk involved in drilling activities, however, successful

development of the technology could reduce the risk and the cost significantly.

Recommendations Considerably more R&D development is needed before this technology can be utilized, however, it's potential

for cost and risk reduction is significant and further technology development should be encouraged.









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Project 9. Stimulating Formations Thermally, Diamond Exploration





Problem A shallow, 200 foot deep, 6 foot thick, low gravity oil sandstone formation is non-producible.

Proposed Solution Drill 3 electrode wells in a triangular pattern 100' apart with a producing well in the middle. Insert copper

& Technical electrodes, connected to a 400-cycle generator, into the formation. Pass an electrical current through the

Description shallow, low pressure, heavy oil reservoir to generate heat to activate dormant gas and lower the oil viscosity,

mobilizing the oil. Inject inert gas if necessary to increase reservoir pressure.

Reservoir Setting The Cottage Groove sand at 200-300 ft. depth is a shallow, low gravity oil sandstone in Miami County,

& Information Kansas, and is non-producible. Earlier attempts to waterflood this zone were unsuccessful. The oil zone is

approximately 6 ft. thick and the underlying water zone is approximately 2-3 ft. thick.

Objective/intent Program Objective: Increase reserves.

Project Objective: Heat the reservoir by passing an electrical current through the reservoir to activate

dormant gas and lower the oil viscosity, mobilizing the oil. Inject inert gas if necessary to increase reservoir

pressure.

Working Heat formation and attempt to recover non-producible heavy oil vs. no development with zero recovery.

Hypothesis

Baseline & Zero pre-project oil production. No forecast was provided. Small diameter, rotary core sample oil

Forecast saturations were 25-35%.

Compare: There are no results to compare. A 50 ml. downhole oil sample was recovered from one of the electrode

Actual vs baseline wells. The oil sample had an API gravity of 210 and viscosity of 1,730 centipoises. The oil saturation was

probably too low to be producible.

Economic? There are no results for economics. All costs were lost. Estimated total project proposal cost was $99,000.

Due to high cost of fuel to run the electrical generator and the low quality of the oil, it is unlikely that such a

project would be economic even if some oil had been produced.

Project Objective The project objective was not met. The formation at the electrode wells was heated from 58 0F to 101 0 F, but

Met? no oil was produced. The formation at the center producing well was not heated. Injection of inert gas at the

electrode wells had no effect on oil production, although gas communicated to the center producing well.

Program Objective The program objective was not met because no oil was produced and no reserves were added.

Met?

Lessons Learned Either insufficient heat was generated beyond the immediate vicinity of the electrode wells and/or the

reservoir oil saturation was at irreducible.

Application If the technology could be developed, and demonstrated to be practical, feasible, and economic there could be

(area/region) considerable application to all shallow, heavy oil reservoirs.

Limitations Application would be limited to recovery of heavy oils that could become mobil at moderate temperature

increases.

Recommendations Additional research would be required to determine the extent of the formation effected by the temperature

increase and to determine if the technology is practical, feasible, and/or economic.









27

Project 19. Oxygen Activation Log, J. R. Pounds





Problem Well was shut down due to various down-hole mechanical problems which were caused from casing leaks.

Proposed Solution Run an Oxygen Activation Log in the well to locate casing leaks, then repair with casing patch and/or cement

& Technical squeeze. Using the Oxygen Activation Log instead of conventional bridge-plug and packer will save time

Description and costs.

Reservoir Setting The Gaddis Farms A-1 oil well producing from the Rhodessa formation @ 11,120 ft., in the Bolton Field,

& Information Hinds County, Mississippi, is off production because of remedial problems due primarily to ruptured and/or

leaking casing.

Objective/intent Program Objective: Increase production.

Project Objective: Run an Oxygen Activation Log in the well to locate casing leaks, then repair with casing

patch and/or cement squeeze.

Working Use Oxygen Activation Log to locate casing leaks vs. using more costly and time consuming usual bridge-

Hypothesis plug and packer method. Locate and repair casing leaks vs. leaving well shut-in.

Baseline & Well was shut-in prior to the project. Forecasted production 60 BOPD & 100 BWPD after remediation.

Forecast

Compare: No incremental production due to new technology application. No new technology was used in this project.

Actual vs baseline

Economic? There are no economics to run.

Project Objective The project objective was not met. The proposed Oxygen Activation log was not applicable for locating

Met? casing leaks in this producing well, and thus was not used. Casing leaks were located and repaired using

conventional techniques.

Program Objective The program objective was not met because no new technology was used in the project.

Met?

Lessons Learned Use of the proposed technology was not sufficiently investigated prior to the project proposal.

Application The Oxygen Activation Log is used to detect water movement past the tool in a flowing well and is some-

(area/region) times be used to detect casing leaks in active injection wells. The log requires water flowing past the tool in

order to function properly.

Limitations Technology cannot be applied in a non-flowing well and requires water in the flowing stream.

Recommendations This project was approved based on an indication that the proposed technology is generally applicable to the

types of production problems cited, but the specifics of the production problem in this project precluded the

technology from being applicable. In this case, preliminary contact with a logging service company would

have pointed out that the tool could not be used for the proposed application.









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APPENDIX B



DISCUSSION OF LESSONS LEARNED





This section consists of discussions describing each of the projects that were less fully

successful (sorted by their relative degree of success, most successful first)



Project 17. Cost Effective Water Disposal, Harry A. Spring



Project 1. Horizontal Drilling to Increase Production, Cleary Exploration LLC



Project 3. Improved 3-D Seismic Processing Techniques, Brothers Production Company



Project 4. Integrated Exploration Using 3-D Seismic, Double-Eagle Enterprises



Project 2. Horizontal Drilling for Improved Wellbore Drainage, EDCO Oil Company



Project 5. Telluric Surveys, Keener Oil & Gas Company



Project 9. Stimulating Formations Thermally, Diamond Exploration



Project 19. Oxygen Activation Log, J. R. Pounds









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Project 17. Cost-effective Water Disposal

Carmichael Sand, W. Lawrie Field, Logan County, Oklahoma



Harry A. Spring, operator

Ardmore, Oklahoma



Technology Area: Water Production



Problem:

High water production causing high water disposal costs. Gas well making so much water that water

disposal (hauling) became cost prohibitive and the well was shut-in.



Summary:

A commercially available down hole simultaneous gas production/disposal tool was installed in a watered-out

gas well to produce gas and economically dispose of the produced formation water. The device allows gas

production to occur while simultaneously allowing produced formation water to be injected into a lower

formation without first being lifted to the surface. Additionally, dewatering of the producing formation near

the well bore should allow higher flowing gas rates. The tool was installed in the well, but after several

months of production the disposal zone pressured-up and would not take water with the existing pumping

equipment due to the limited injection capacity of the disposal zone and a larger volume of produced water

than was originally anticipated. The well was then abandoned due to the high cost of water disposal (hauling).



Lessons Learned:

The injection capacity of the disposal formation (Virgilian formation, 3,398-3,944 ft.) was inadequate for the

volume of formation water being produced. The disposal formation pressured up and stopped taking water

and the well was abandoned. The DHI tool appears to have functioned properly as designed.



The formation produced more water than was anticipated and more than the disposal formation was capable

of taking. It was anticipated that the producing formation could be de-watered, to zero water production,

which would probably have reduced the volume of water being produced substantially.



The producing formation did not de-water before the disposal formation pressured up, and may not have de-

watered at all. The well had started producing a significant amount of water prior to the project indicating

that the well may have been watering-out (water encroachment, water break-through, coning, etc.) and

would quite likely have continued to produce water even at the anticipated higher gas production rates.



Basically, if the producing formation had de-watered as proposed and the anticipated volume of water been

produced thereafter, the disposal zone may have been adequate. It is doubtful that the well would have

eventually de-watered as the well was producing a significant volume of water prior to the project and

probably would have continued to do so. The disposal zone pressured-up to an indicated 4,000 psi bottom-

hole pressure at 300 BWPD so even at the pre-project rate of 200 BWPD, it would probably have pressured-

up eventually anyway. After an indicated few months of production at 300 BWPD the well still had not de-

watered, indicating that the water production would probably not return to rates lower than the 200 BWPD

pre-project rate, well above the zero BWPD forecasted post-project rate.



Application of this technology in this project did not take into consideration that the producing formation

might be watered-out and might not be adequately de-watered (may continue to produce large volumes of

water) and/or that the target disposal zone might not have adequate injection capacity. Adequate disposal

capacity must be available in order for this technology to be successfully applied. The disposal zone should

30

have been fully tested to determine it's injection capacity and evaluation conducted to determine whether or

not the well might continue to produce at the pre-shut in water volumes.



The error was made in assuming that the producing formation would quickly de-water down to very low

water production rates and that a large injection capacity would not be necessary. The operator may have

considered that it was worth taking the risk (i.e., a fair chance that the well would pump-off before the

disposal zone would pressure up) as that may have been their only choice, i.e., to go ahead and take the

chance (as evidenced by the fact that following failure of the project, the well was abandoned).









31

Project 1. Horizontal Drilling to Increase Production

Hunton Formation Dolomitic Limestone, Pottawatomie County, Oklahoma



Cleary Exploration LLC, operator

Oklahoma City, Oklahoma



Technology Area: Drilling



Problem:

Production rates and ultimate recovery vary widely and unpredictably from one well to another in this area

of the fractured Hunton Limestone formation and production from new wells is often marginal to non-

commercial. The inconsistent and unpredictable results appears to be due to the specific reservoir fracture

and/or paleokarst (karst) system intersected (or not intersected) by the vertical wellbore.



Summary:

A horizontal wellbore was drilled in a low-permeability dolomitic limestone reservoir in an attempt to

intersect additional fracture and/or karst systems to increase oil production. Initial results indicated

significantly improved total fluid production from the horizontal wellbore, but the beam pumping unit being

used to produce the well was incapable of moving the amount of fluid produced by the horizontal hole. It

was estimated that the produced volumes could exceed 200 BOPD, possibly stabilizing around 100 BOPD,

if the well was equipped with high lift production equipment. However, the first 200' of the horizontal hole

collapsed before a submersible pump could be installed to fully test the production capacity of the horizontal

wellbore. Attempts to clean out the horizontal section were unsuccessful and the hole was lost.



Lessons Learned:

The horizontal hole collapsed and the hole was lost before the well could be produced to capacity. The

horizontal section was drilled and completed as proposed although hole stability difficulties were

encountered during drilling.



It appears that the horizontal hole collapsed due to exposure of the overlying Woodford shale to the open

horizontal borehole. The horizontal hole had drifted up into the overlying Woodford shale while drilling the

horizontal section.



Inability to maintain hole stability during drilling probably set up the conditions which led to the hole

collapsing. Comments in the Final Report indicate some concern for drilling the "troublesome Woodford

shale" and additional precautions should have been taken. Maintaining better hole stability while drilling

and/or setting a production liner through the open-hole section might have prevented the hole from

collapsing, but would have contributed significantly to the cost of the well.



Redesign of the drilling program and of the drilling assembly along with the experience gained from this

project should help to improve the chances of success in future activities. The service company proposed

several modifications to the drilling program in the Final Report for the project.









32

Project 3. Improved 3-D Seismic Processing Techniques

Ellenburger/Strawn Dolomite, Fluvanna SW Field , Borden County, Texas



Brothers Production Company, operator

Midland, Texas



Technology Area: Exploration



Problem:

Unable to map Ellenburger reflections in 3-D seismic survey for identification of bypassed oil for selecting

in-fill drilling locations due to incorrect time to depth conversion of seismic horizons.



Summary:

A new analytical seismic interpretation algorithm was developed to map the Ellenburger dolomite in West

Texas. Reprocessing and reinterpretation of the existing 3-D seismic data resulted in confidently mapping

of reliable Ellenburger dolomite reflections, showing probable faulting which has identified locations of

possibly bypassed oil. Reinterpretation using the analytical function has identified several Ellenburger

structural anomalies which will be drilled if and when oil prices recover and stabilize. The reinterpretation

did not support the two pre-project dry hole wells and the wells would not have been drilled if the

reinterpreted data had been available. Drilled one well to test a Wolfcamp structural anomaly identified

from the reinterpreted 3-D seismic data (which was on structure, but wet). The well resulted in a

commercial oil discovery in the shallower Spraberry (not Ellenburger), identified from drilling data. No

Ellenburger wells have yet been drilled to verify the reinterpreted 3-D seismic maps.



Lessons Learned:

Reinterpretation of the 3-D seismic identified several Ellenburger prospects which have not yet been drilled.

One Wolfcamp formation dry hole was drilled based a structural anomaly identified from the reinterpreted

3-D seismic data. The Wolfcamp structure was present as indicated, but the structure was wet. However, a

commercial producer was completed in the shallower Spraberry based on shows when drilled, but was not

identified from the reinterpreted 3-D seismic. The well was subsequently completed in the shallower

Spraberry (identified from the well data) and was completed as a commercial producer with an estimated

150,000 to 200,000 BO reserves. The well was not drilled to the Ellenburger and did not result in

production from the Ellenburger formation.



The reinterpreted 3-D seismic indicated that the Ellenburger top in both of the pre-project dry hole wells was

lower than predicted from the original 3-D seismic data due to inherent interpretation inaccuracies and

processing artifacts of the time to depth conversions. The two dry holes would not have been drilled had the

reinterpreted 3-D seismic been available.



The quality of the structural map may have been improved by the reinterpreted data, as indicated by the

Wolfcamp prospect, but obviously not accurately enough to ensure the success for every well drilled.

Seismic data interpretation did not eliminate the risk involved in the drilling activities, although,

improvements in the interpretation may reduce that risk over-all to an acceptable confidence level. Several

more wells would need to be drilled in order to determine if the success rate can be improved by the

reinterpretation (i.e., a statistical matter).









33

Project 4. Integrated Exploration Using 3-D Seismic

Wilcox Formation, Kay County, Oklahoma



Double-Eagle Enterprises, operator

Tulsa, Oklahoma



Technology Area: Exploration



Problem:

Unable to locate reliable drilling prospects using subsurface and 2-D seismic data resulting in a low

exploration success rate.



Summary:

The original proposal was to conduct a 3-D seismic survey to supplement existing 2-D seismic data and

conduct surface microbial analysis to better target drilling prospects in the Wilcox sandstone formation.

Existing 2-D seismic data did not provide sufficient information to identify the more likely productive areas

of the Wilcox structure. The proposal was modified to eliminate the surface microbial survey due to the

operators budget constraints. 3-D seismic data was acquired and processed for two prospects. The 3-D

seismic data interpretation on the first prospect did not support the existence of a structural anomaly that had

been indicated by the 2-D seismic data, thus a well to test the structure was not drilled on that prospect,

thereby possibly preventing the drilling of a probable dry hole. Based on the 3-D seismic data interpretation

on the second prospect, a well was drilled to test the structure, but due to an unanticipated thickening of the

overlying formation, the Wilcox was structurally flat (low) and subsequently wet. Review of the seismic

data suggested that although the top of the overlying formation was structurally high, as confirmed by

drilling data, the 3-D seismic data did not suggest that the overlying formation was thickening and that a

possible seismic velocity pull-up had been interpreted as a favorable underlying Wilcox structural high.

Information and experience gained from this project can be utilized in future development activities.



Lessons Learned:

One dry hole was drilled based on the 3-D seismic data. The Wilcox top was flatter (lower) than predicted

and the formation was wet. A second well had been proposed on another prospect identified from the 2-D

seismic data, but the well was canceled because the 3-D seismic data did not confirm the 2-D seismic

interpretation.



After the drilling and log evaluation of the dry hole well had been completed, the 3-D seismic data was

reviewed and found to suggest that the structural anomaly previously identified may be only a seismic

velocity pull-up instead of a geological feature as original interpreted. Several geophysicists had reviewed

the prospect database prior to drilling the well and had missed that interpretation.



Although the results were disappointing, the 3-D seismic program may be successful in providing useful

information which can be integrated into future drilling plans in the area. Several more wells would need to

be drilled in order to determine if the success rate has been improved, (i.e., a statistical matter).









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Project 2. Horizontal Drilling for Improved Well-bore Drainage

Trempealeau Formation, Shaver-Neff Unit, Morrow County, Ohio



EDCO Producing, operator

Mt. Gilead, Ohio



Technology Area: Drilling



Problem:

Low oil production due to heterogeneous formation and low reservoir energy.



Summary:

Attempted to drill a horizontal well bore in the energy depleted compartmentalized reservoir to intersect

accumulations of trapped oil. Experienced horizontal drilling problems, including difficulty maintaining

hole angle and direction, which resulted in abandoning horizontal drilling efforts at approximately 32 feet of

horizontal section instead of the 300-600 feet targeted. Set rod pump at top of curved section and placed on

production. After seven weeks of production from the horizontal well bore the fluid level decreased to the

pump level and production rates declined to 2 barrels of oil and 7 barrels of salt water per day, lower than

the rates from the original vertical well bore. The reason for the disappointing result was the inability of the

pump to remain submerged (low fluid level). The operator then ran a coiled tubing anchor with check-valve

below the rod pump into the curved section. Well production stabilized at pre-project rate of 5 BOPD and

15 BWPD. The well was eventually shut-in due to low economics.



Lessons Learned:

Drilling of the horizontal hole was suspended approximately 30 feet into the curved section because of

severe hole problems and the extreme difficulty in keeping the hole direction stabilized.



Approximately 30 feet into the curved section (approximately 45o inclination), the fractured dolomite

formation began to crumble and slough into the borehole. The drilling assembly became stuck and had to be

fished out. Based on the inability of the wellbore to stay on course and the corkscrew of the borehole, in

conjunction with the formation hole problems, the horizontal drilling attempt was suspended.



Drilling the tight radius build section with air in the fractured dolomite probably created the hole problems

and/or may have created equipment problems in addition to the formation problems. Numerous equipment

problems were reported during drilling, indicating that the drilling assembly was not properly/adequately

designed for the unanticipated drilling conditions encountered.



It is difficult to determine whether or not production might be improved with a horizontal borehole in this

formation because the horizontal section was not completed and thus there was no production test. It does

appear, based on the results of the project, that horizontal drilling in this formation is difficult and that

several drilling problems will need to be addressed before another attempt can be reasonably made.









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Project 5. Telluric Surveys

Wilcox Sand, Bates-Springer Lease, Creek County, Oklahoma



Keener Oil & Gas Company, operator

Tulsa, Oklahoma



Technology Area: Exploration



Problem:

Locate structure with alternative geophysical technology to reduce finding costs for drillable structures.



Summary:



A telluric survey was used as a tool to define subsurface oil and gas bearing structural traps. An

electrotelluric (telluric) survey is a measurement of the resonance signal created when atmospheric

generated electromagnetic pulses penetrate the earth's surface, creating a secondary electrical field which

propagates downward and ultimately resonates from subsurface beds of contrasting resistivities. A well was

drilled to test a subsurface structural anomaly identified from telluric survey data interpretation, but the

target formation was not on structure and was dry. Review indicated that formation tops and target zones

predicted by the telluric data were either undefinable or shallower than the actual depth encountered by the

drilled well.



Lessons Learned:

A well was drilled to test the accuracy of the telluric survey interpretation, but the target formation was not

on structure and the well was a dry hole. The target formation was 22 feet lower than indicated by the

telluric interpretation. The structural anomaly was misidentified from the telluric survey data. The telluric

survey interpretation was not precise enough to give reliable results.



This project proposed the use of a technology that is still in an early developmental phase. The concept is

feasible, though of low/or limited probability of success at the current stage of development. The project

failed because the survey interpretation results were not adequate enough to accurately define the structure.

However, a telluric survey costs considerably less than a seismic survey and leaves little, if any,

environmental impact, and thus certainly warrants further consideration and development by the industry.









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Project 9. Stimulating Formations Thermally

Cottage Groove sand @ 250-300 ft., Paola-Rantou-Shoestring Field, Miami County, Kansas



Diamond Exploration, operator

Paola, Kansas



Technology Area: Improved Oil Recovery



Problem:

Low oil recovery due to low oil gravity and low reservoir energy.



Summary:

High-voltage electrical current was used to generate heat in a small, heterogeneous, shallow, heavy oil (low

gravity) reservoir in an attempt to improve oil recovery. Copper probes were placed at the formstion in each

of three wells in a triangular pattern approximately 100 feet apart with a producing well in the center. The

probes were energized by an electrical current over a period of six days. The reservoir temperature at the

probe wells was elevated from 58oF to 101oF and a small, non-commercial quantity of 21oAPI gravity

viscous oil was recovered from one of the probe wells. Inert gas was injected into each of the probe wells

after the formation was heated and communication was immediately established with the producing well.

However, the formation temperature at the producing well did not increased and no oil was recovered from

the producing well.



Lessons Learned:

The project failed to produce any oil, even though the formation at the electrode wells was heated from

58 oF to 101 oF. The formation at the center producing well located 57 ft. away was not heated. Injection of

inert gas at the electrode wells had no effect on oil production, although gas communicated to the center

producing well. A small amount of oil was recovered on a wire line from one of the electrode wells during

the demonstration project. The oil gravity was 20 oAPI with a viscosity of 1,730 centipoise at 74 oF.



Core samples were obtained from a well on the lease and analyzed in 1982. The reservoir had good

permeability and porosity, ranging from 110 md to 169 md and from 26.9% to 28.1% respectively. Analysis

of the core samples indicated oil saturations in the range of 21% to 38 %.



There are several possible explanations (or combinations of explanations) as to why there was no oil

produced, even at the electrode wells:

- The oil saturation was at, or close to, irreducible and too low to be producible (difficult to determine).

- The oil was too viscous to flow, even at 100 oF.

- There was not enough heat generated beyond the immediate vicinity of each individual electrode well

to heat the formation enough to mobilize the oil.



Either 101 oF is not hot enough to mobilize the oil, or the oil saturation is too low to be producible.

Probably the latter, because, if the core oil saturations had been flushed during coring from some higher in-

situ value to the lower (and possibly irreducible) measured core saturations then there should have been

some mobile oil in-situ which should have been produced at the electrode wells, especially when heated.

The center producing well reportedly produced water with only a show of oil for some time prior to the

project start-up, indicating irreducible oil saturations may exist at the reservoir conditions. Earlier attempts

to waterflood this formation have been unsuccessful although there appears to be good communication

between wells.



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There are several additional problems/concerns associated with the application of this technology:

- The formation did not heat up at the center producing well even though it is only 57 ft. from, and in

the center between each of the three electrode wells. It is questionable as to how much of the

formation may have been heated by the process.

- The oil is of poorer quality and thus of lower value, and may not be of enough value to off-set the cost

of the fuel required to run the electrical generator.

- The process was essentially a direct short to ground and the current path through (or into) the

formation is not known.

- The state-of-the-art for this technology is not at all well developed.

- Waterflood attempts in this reservoir in the past have been unsuccessful although there appears to be good

communication between wells.



A sample of the heavy oil should have been obtained and tested to determine the temperature required to

induce flow prior to the project. Additional evaluation should have been conducted to establish the in-situ

oil saturations to determine whether or not there was any recoverable oil in place to start with.



Even though the technology was designed by an electrical engineer it was essentially a low budget R&D by

trial-and-error project. The technology is not at all well developed and very little effort has been conducted

in this technical area. There are too many unknowns for the current stage of development of this technology.

The project proposal evaluation should have considered the risk involved in this rather novel and new

experimental technology.









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Project 19. Oxygen Activation Log

Rodessa Sand, Bolton Field, Hinds County, Mississippi



J. R. Pounds, operator

Laurel, Mississippi



Technology Area: Wellbore Problems



Problem:

Well shut-in due to holes in the casing.



Summary:

It was proposed to use an Oxygen Activation Log to locate holes in casing for repair as a way of reducing

costs. During initial investigation by the operator, the logging service company advised that the Oxygen

Activation Log was not designed for casing hole detection in the particular situation that existed in the target

well. The target well was on rod pump, shut-in, and not flowing. The logging tool requires the flow of

water past the tool in order to be applicable. Conventional pressure testing methods were then employed to

locate the casing holes and conventional casing leak repair methods were employed to successfully repair

the leaks.



Lessons Learned:

This project failed to meet the requirements of the program because the proposed technology was not

applicable to the situation and was not applied. The production problem was solved and the well was put

back on production using conventionally available (non-R&D type) technology to solve and correct the

problem.



Even though the Oxygen Activation Log can, in certain instances, be used to detect casing and/or tubing

leaks, the log was not designed for this particular application, i.e., in a non-flowing well. The log requires

water flowing past the tool in order to function properly. The log uses a neutron generator to temporarily

activate the oxygen molecules in the water, then uses a set of detectors to detect the slug of activated water

as it flows past the detectors. Preliminary contact with a logging service company before the project was

proposed would have pointed out the fact that the tool could not be used for the proposed application.









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