Sand Consolidation Experience in Niger Delta by klutzfu58


									Sand Consolidation Experience in Niger Delta
Dr D Appah, Non-member
In situ sand consolidation (SCON) methods are sensitive to placement techniques. Adequacy of SCON and the performance of selected methods are assessed to provide guidance on the implementation of the requirements and thereby help production engineers economically plan workovers. Productivity indices and Well Inflow Quality Indicators (WIQI) of five Niger Delta wells have been studied before and after installing SCON device. It is found that clean perforations and sufficient pump pressures to ensure proper mixing of chemicals with formation sand are necessary. Most chemical treatments are not water tolerant and these may fail at high water-cut (BS and W ≥ 50%) and difficult in shaly sands. Epoxy sand consolidation treatment at well completion results in about 80% success and a 91.44 cm– 121.92 cm deep radius stabilization around the wellbore. The overflush system is preferred where accurate displacement of resin solution becomes difficult. Deviated wells give better results because the tubing is very close to the top perforations. Consolidation systems tolerate ≤ 20% clay content and downwhole temperature of 15.5 o C − 43.2 o C .
Keywords: Sand consolidation; Niger delta; Well flow quality indicators

NOTATION B : formation volume factor h H PI r R : : : : : effective pay thickness, m height of perforations, m productivity index wellbore radius, m treatment volume, m3 well inflow quality indicator


INTRODUCTION Improper application of sand consolidation technique results in poor sand control and in some cases damage1. The bleeding and accumulation of fines alter significantly the permeability of the near-wellbore region2. Consolidation, as a method of sand control, is often used in short intervals where for reasons of small pipe dia, abnormal pressure which make through tubing operation advisable, top zone of a dual completion, offshore or isolated location where tubing hoist is not available, among others, a gravel pack cannot be applied3. This is a cost containment measure. Several oil reservoirs in the Niger Delta show fines migration behaviour under water drive4. The stability of subsurface formations in the vicinity of a borehole is a problem of continuing interest in the petroleum industry5. Chemical binder is placed in the formation to provide grainto-grain cementation of the naturally unconsolidated or weakly consolidated sands. Coarse and non-uniform sand
Dr D Appah is with the Department of Petroleum Engineering, University of Port Harcourt, Nigeria. This paper was received on November 19, 2000. Written discussion on the paper will be received until November 30, 2003.

formations in the upper section, multi-stage reservoir completions and abnormal pressure in some wells are found in the Niger Delta6, Chemical method (SCON), unlike the mechanical method (gravel pack), frees the wellbore of obstruction. It is particularly good for multiple completions and it immobilizes small sand particles at some distance in the formation and thereby minimizes the hydrodynamic forces in the near-wellbore region7. It has been reported that SCON system works best initially in completed wells because the formation is least disturbed8. Causes of failure include contaminated chemicals, improper placement and excessive injection pressure resulting in poor repack of sand producing formation9. Bench-mark evaluation of the technologies of sand consolidation in the Niger Delta has been carried out to determine the performance capabilities and review some of the considerations that should be observed. High injection pressures indicate need for clean-up before consolidating. SCON TECHNIQUES FOR NIGERIA The procedures for sand consolidation are divided into four main techniques, namely, standard rig operation with retrievable packer; tubing-conveyed string; coiled tubing; and long zone/selective treatment. Several consolidating materials, such as, crude oil coke and nickel plating, have been used in the past by researchers. At present, the chemical binders, such as, phenol resin, phenol formaldehyde, epoxy, furan or phenol-furfuryl provide cementation. The solidified plastics convert the loose sands in the perforations and matrix pore throats to a strong artificial sandstone external to the wellbore. RESERVOIR CONDITIONING Recommended wellbore preparation consists of cleaning the perforations and stabilizing the formation. The reservoir is operative under water drive. A series of fluids is injected into 1

Vol 84, September 2003

the formation to oil-wet the sand surfaces prior to treatment for proper grain coating and to flush the aqueous environment. A 50-50 mixture of diesel oil (non-damaging fluid) and medium aromatic oil is injected to leave an aromatic oil in the pore space so that the epoxy can be displaced. The diesel oil serves as a spacer and removes reacted or unreacted acid from the pore space, while isopropyl alcohol (IPA) absorbs any aqueous connate film. This mixture makes the silica surface accessible to the epoxy. Ethylene glycol monobutyl ether (EGMBE), as a preflush, is a mutual solvent for aqueous and non-aqueous materials (clays, feldspars or carbonates). It removes extraneous materials from the sand, making the mineral surfaces more accessible to the consolidating plastic. Phenol-formaldehyde plastic externally catalysed is beneficial in wells that require acidising before consolidation. In the Niger Delta 620.97 l/m HCl and 100 1241.93 l/m mud acid of the treated interval are used to enhance injectivity, by removing fines and formation damage. The well is then backflowed at moderate rates for 12 h to minimize the risk of reprecipitating dissolved silica from the spent acid. Good injectivity allows safe placement of the resin solution and avoids fracture gradient of the formation. A catalyst to cure the resin is either preformed on the surface (external) or injected in situ after the chemical binder. Overflush is recommended for shaly sands. Preflush fluid (IPA) cleans tubing, surface equipment and prepares the formation. CHEMICAL TREATMENT Treatment can be performed through coiled tubing (rigless location) or on a tubing conveyed packer (TCP) string, where perforation and consolidation are done in one trip. The main consolidation systems in the Niger Delta are Eposand (20, 30, 112), Wellfix DP 2000 (improved overflush system with epoxide and amine, for wider temperature range), K-2000 (for dirty sands because of high resin content at 15.5 o C - 135o C ) and sandlock (gravel-coated internally catalysed epoxy resin with silicon coupling agents for sand production). Specific applications depend on the type of well (oil, gas or water), sand quality (clean/dirty or well sorted), type of catalyst or curing agent (internal on resin or external in overflush), temperature range, production history and crude viscosity. Long intervals (> 3.65 m) are perforated in 1.914 m–3.048 m zones for optimum resin placement. These zones separated by smaller gaps of ≥ 2.438 m are then selectively consolidated with a straddle packer system. The resin filled pore spaces are overflushed, during displacement with diesel, with a heavy oil to displace excess resin from rock pore spaces and restore permeability. Well shut-in time to harden (cure) resin into a permeable synthetic matrix, depends on downhole temperature and resin composition. Ideally preflush should increase formation permeability to improve plastic solution injectivity, minimize formation damage, ensure proper setting of polymer, establish a good bond between matrix materials and the consolidating polymer. 2

Unreacted acid can decatalyse a base-catalysed plastic and preflush untreated for clay minerals will cause clay dispersion and swelling. Treatment success is judged against service life of plastic (improved field performance), good set strengths, high permeability retention and sensitivity to the retention. Wells were selected for treatment that could not be kept on production using other methods of sand control routinely used in the Niger Delta. These methods are gravel packing, frac-pack or raising the pump. Procedure Interval is reperforated with 2 unijet [0.13 hole/cm] zero phase perforator, open to production on 81.28 cm bean. The resin content is low (15% by volume) and it is basically applied over a bottomhole temperature (BHT) range of 43.2 o C – 110o C . String is displaced with 6.359 m3 diesel oil and packer set. Valve and tubing plug on top of the tubing stop are set and pressure tested (210.92 kg/m2) for 15 min. Injectivity test carried out successfully with the diesel oil if squeezing is at a minimum rate of 2 barrels per minute (bpm). For satisfactory injectivity 7.949 m3 of crude is pumped with short string and annulus closed, acid wash (based on length of perforations) which includes a 10% HCl (15.898 m3–31.79 m3) barel, 3% HF (23.84 m3–47.69 m3) mixture with 0.1589 m3 each of inhibitor, surfactant and iron control at a maximum surface pressure of 2500 diesel 1.907 m3-3.179 m3; IPA 1.907 m3-3.179 m3, Eposand 1.367 m3-2.225 m3 and overflush 3.815 m3-5.723 m3 are pumped into the well. Overflush is displaced with string content of completion fluid. Packer is pulled up one stand, reset for ≥ 12 h depending on resin system and BHT, plastic waited on (shut in) for 12 h–24 h, then packer is pulled loose and well is observed for losses. Loss is noticed at less than 10 bph which does not require cure. The well is reverse circulated clean, through 61-cm choke to filtered brine past the perforations. Where this is not possible, a bit is made, scrapper run and assembly pulled out of hole. It is required that after waiting on plastic, the well be produced to about 31.80m3 crude oil through coiled tubing (CT) into the flowback tank. Volumetric Requirements The volume of SCON chemicals to be injected into the formation is calculated based on the ‘pore volume’ of the zone to be treated. The pore volume depends on porosity, height of perforations, treatment radius and wellbore radius. Assuming the zone treated to be a perfect sphere and linear flow, the pore or treatment volume can be expressed as10
2 2 V = πφ R − r H + 1.33 πφ R − r







where φ is the porosity; H, the height of perforations; R, the treatment radius and r is the wellbore radius approximated from openhole bit size. For most fields in the region, average porosity is 0.3 and the optimum treatment radius range is 91.43 cm–121.92 cm. For casing with gauged open hole size of 21.60 cm and 10.16 cm IE (I) Journal—CH

Table 1 Well 1 2 3 4 5

Placement parameters Treatment Time April 1998 March 1999 October 1998 June 1999 May 1999 Length, cm 182.88 213.36 243.84 274.32 304.80 Volume Used, m3 12.718 19.078 2.066 22.735 24.961 Method DP2000 K200 Epasand Epasand Sandlock

productivity index (PI) changed with time after consolidation. The treated wells had earlier gone through series of other workover operations, so PI before SCON PI b replaced ideal PI in the evaluation as follows WIQI =
PI after PI real = PI ideal PI before WIQI a − WIQI b WIQI b

b g


Relative WIQI =


penetration, equation (1) becomes in the condition V = 2.5 H + 1.271 m3 (2) A 152.4-cm perforation gives a one pore volume equivalent to 32.60 m3. However, the pore volume varies among wells. RESULTS AND DISCUSSION In this section, the details of placement effectiveness and post treatment response are discussed. Placement Effectiveness Treatment was carried out on 5-wells. Sandcut success was analyzed based on well inflow quality indicator (WIQI) and
Table 2 Production response before and after treatment Production for Post Previous 6 months qo, qw, bbl/d Sandcut, kg/1000 kg
420 × 0.10589873 Surrounding wells 2 847 × 0.10589873 Surrounding wells 3 860 × 1000 × 0.10589873 950 × 0.10589873 400 × 0.10589873 350 × 0.10589873 850 × 0.10589873 1010 × 0.10589873 2500 × 0.10589873 2900 × 0.10589873 6.6 23 22.3 30 13 21 18 25 1250 × 0.10589873 1030 × 0.10589873 2420 × 0.10589873 900 × 0.10589873 1030 × 0.10589873 1143 × 0.10589873 930 × 0.10589873 1515.7 × 0.10589873 850 × 0.10589873 700 × 0.10589873 250 × 0.10589873 300 × 0.10589873 900 × 0.10589873 1020 × 0.10589873 4000 × 0.10589873 6000 × 0.10589873 1.5 6.6 1.0 18 4.2 2.1 7.5 3.2 600 × 1260 × 0.10589873 900 × 20 30.00

Positive WIQI Sandcut of less than 4.536 kg per 159 m3 of crude oil produced (10 pptb) has generally been set as the cut-off in the region. Table 1 gives placement parameters for the 5 successful jobs. The consolidation systems work best when the clay content is between ≤ 20% and static bottomhole temperature is between

15.5 o C and 43.2 o C .
Post Treatment Response All the 5-wells successfully sand consolidated now have 12 month-19 month of post treatment production history. These consolidation materials (epoxy, etc), for the most part,

Treatment Production Response qo, qw, bbl/d Sandcut, kg/1000 kg
1.5 8.0


qo, qw, bbl/d

Sandcut, kg/1000 kg
1.7 8.4

qo, qw, bbl/d

Sandcut, kg/1000 kg
1.3 8.5


2200 × 0.10589873 1000 ×

1000 × 0.10589873 830 ×

1500 × 0.10589873 950 ×

800 × 0.10589873 700 ×

1100 × 0.10589873 870 ×

750 × 0.10589873 610 ×

1060 × 0.10589873 1080 × 0.10589873 2410 × 0.10589873 1650 × 0.10589873 1010 × 0.10589873 1160 × 0.10589873 745 × 0.10589873 1250 × 0.10589873

720 × 0.10589873 600 × 0.10589873 200 × 0.10589873 200 × 0.10589873 905 × 0.10589873 1025 × 0.10589873 6000 × 0.10589873 7000 × 0.10589873


1000 × 0.10589873

700 × 0.10589873 600 × 0.10589873 200 × 0.10589873 180 × 0.10589873 860 × 0.10589873 1005 × 0.10589873 5500 × 0.10589873 5000 × 0.10589873



895 × 0.10589873


0.10589873 360 × 0.10589873


2001 × 0.10589873


Surrounding wells 4

500 ×


1600 × 0.10589873


0.10589873 1050 × 0.10589873


1000 × 0.10589873


Surrounding 1250 × wells 5 0.10589873 1080 × 0.10589873 Surrounding 1512 × wells 0.10589873


1050 × 0.10589873



640 × 0.10589873



1160 × 0.10589873


Note : 1 bbl = 1.589873 × 10–1 m3

Vol 84, September 2003


have effectively controlled sand entry. Post treatment productivity index (PI) is averaged as 30 bd/psi per 6-month period and downtime level of 65% to between 30% and 35%. This has helped to increase cumulative oil production. Comparing production response of sand consolidated wells with all four comparable producing wells in the immediate vicinity (offset wells), a success of between 43% and 45% was recorded in six months (Table 2). The resultant permeability reduction is 10%–20%. The chemically consolidated jobs in deep reservoirs are effective for long intervals. Production data are derived by dividing the computer gauged total monthly oil, water and sand-cut by the number of days they were on production (without downtime). Close to the WIQI is another parameter for data analysis, the WIQI – IF, expressed as11 WIQI =
PI after − 1 PI before

CONCLUSION A performance review of eposands consolidation in the Niger Delta reveals the following. q Sand and fill cleanouts from perforations are important for a proper sand consolidation job. q Water-cut in excess of 50% adversely affect the result of sand consolidation. q The optimum treatment radius range is 91.44 cm – 121.92 cm (the average porosity in the region is 0.3), though a 91.44 cm–304.8 cm deep radius can be stabilized, especially in deep wells (> 2438.4 cm). q Better consolidations are obtained in deviated wells. q The consolidation systems work best when the clay content is ≤ 20% and static bottomhole temperature is in the region 15.5o C − 43.2 o C . ACKNOWLEDGMENT The concluding part of this study has been sponsored by the Humboldt Foundation through a fellowship grant to support fines migration research at the Institute of Petroleum, Clausthal Technical University, Clausthal, Germany. The author is indebted to Prof R Gofrani for his constant support through out the study. REFERENCES
1. T W Hamby ( Jr) and F A Richardson. ‘Shell’s Sand Consolidation Experience — Delta Division.’ (Southern District), API Division of Production, Texas, USA, March, 1968. 2. G O Suman, ( Jr). ‘New Completion Fluids Protects Sensitive Sands.’ World Oil Magazine, September 1994, p 55. 3. F Opara and M J Ichara. ‘Sand Consolidation Procedure Review in the Niger Delta.’ (Bachelor of Engineering Dissertation), University of Port Harcourt, Nigeria, 1988. 4. D Appah, M Ichara and A Bouhroum. ‘Aerated Washover Technique in Sand Producing Wells.’ Oil and Gas Magazine, Germany, vol 4, 1997, p 29. 5. H N Vaziri. ‘Theoretical Analysis of Stress, Pressure and fm Damage during Production.’ JCPT, vol 27, no 6, November–December, p 111. 6. D Appah. ‘An Assessment of Sanding Wells at Kirovneft.’ Journal of Institution of Engineers (India), vol 78, March 1998, p 39. 7. D Appah. ‘Pore Pressure Prediction in Abnormally Pressured Wells.’ 33rd Annual Conference Nigerian Mining and Geosciences Society (NMGS), Lle-lfe, Nigeria, March, 1998. 8. P Toma, R W King, P Harns, K N Jha and G Korpany. ‘Partial Exclusion Unconsolidated Heavy Oil Formations.’ Society of Petroleum E Thermal Operations Symposium, Bakersfield, CA, USA, February, 1991, p 13. 9. J N Ugbebor. ‘Evaluation of Chemically Consolidated Sands in the Niger Delta.’ (Bachelor of Engineering Dissertation, University of Port Harcourt, Nigeria, 1999. 10. L W Saunders and H L McKinzie. ‘Performance Review of Phenolic Resin Gravel Packing.’ Journal of Petroleum Technology, February 1981, p 221. 11. Dowel Schlumberger. ‘Sand Consolidation Procedures.’ Dowel Sand Control Services, 1995.


The WIQI–IF qualifies the extent of improvement or damage and a positive WIQ–HF indicates improvement while negative indicates the damage. From the experience in the Niger Delta, the several conditions are assigned necessary to obtain a successful sand consolidation include well selection, based on sanding potential and production rates, especially water-cut judged against nearby wells; thorough sand-wash or well cleaning to condition it; and proper placement to avoid fracturing pressure. The success criteria used are sand production less than 4.536 kg/159 m3 of crude oil produced and continuous flow of wells after consolidation. Decrease in PI in some of the wells could be attributed to depletion of the reservoir energy, which causes high water production chemical consolidations in deep reservoirs (> 2438.4 m) have been found to be less prone to failure. For Basic sediments and water (BS and W) in excess of 50%, the well should be gravel-packed. While there are different sand consolidation systems, requiring specific conditions for applications, generally the interval should be less than 304.8 cm, clay content < 20% – 25%, static bottomhole temperature 20o C - 94.44o C , formation water salinity volume 3%–20%. These conditions cause a resultant permeability reduction of 10%–20%.
Table 3 Well Analysed production data PIbefore Previous 6 months 8.3 11.5 53.2 17.5 20.6 PIafter WIQI WIQI-IF Second Third 6 months 6 months 25.6 29.0 105.0 14.1 18.5 16.7 15.6 102.0 14.0 18.1 1.50 0.53 1.50 0.76 0.86 0.35 0.55 0.50 – 0.16 – 0.11

First 6 months 10.5 12.3 81.6 14.3 19.2

1 2 3 4 5


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