Tui - Amokura - Pateke: Oil Reserves Modeling Reserve calculation factors Low Mid High case case case Net pay to gross pay % 100 100 100 Porousity % 18 22 26 oil Saturation % 75 80 85 Recovery factor % 45 50 55 Shrinkage factor % 85 90 95 (100 x 1/formation volume factor) NPSRS (factors multiplied as fractions) 0.052 0.079 0.115 Net Reservoir Volume (m3) 68,179,700 77,887,100 83,434,300 (from contour modeling) Net Reservoir Volume x NPSRS (m3) 3,520,629 6,168,658 9,634,367 Reserves -- barrels oil (bo) 22,143,350 38,798,393 60,596,316 (m3 to bo = 6.2896, Santos website) Reserves (mmbo) 22.1 38.8 60.6 (producible barrels at the surface) Oil Reserves formula: source: http://aesica.dur.ac.uk/exampapers/Geology/Geology%20exams%202002/Resources%20and% 20the%20Environment%2005204101.pdf (see model answers, last question – with some minor modifications) Reserves = net reservoir volume x porosity x oil saturation x recovery factor x shrinkage factor Net reservoir volume: Area under closure, defined as volume between the seal and the oil- water contact, which is of reservoir quality (i.e. conforms to the porosity and permeability criteria for a reservoir at that location). Porosity: Proportion of the net reservoir with effective porosity – i.e. connected pore space. Porosity determined using core or wireline techniques to measure or estimate. Wireline tools include density, sonic, neutron and resistivity. Saturation: Proportion of the pore space which is occupied by oil. Determined from wireline data, particularly resistivity tools, using Archie Formula. Recovery factor: Proportion of the in-situ oil-in-place which can be recovered at the surface using known technology. Recovery factors are generally in the range 30 – 60 % for oil fields, and have improved over the last 40 years due to secondary and tertiary recovery techniques, such as water flooding, gas injection, hydraulic fracture stimulation. Information comes from engineering data and production experience of nearby fields. Shrinkage factor: Proportion of remaining oil volume at the surface after internal gas has exsolved ( = 1/(formation volume factor)). Related to the gas-oil ratio (GOR). As oil moves towards the surface and lower pressures, gas comes out of solution and must be separated. The volume of oil reduces in proportion to the gas coming out of solution. Information comes from analysis of the oil and PVT property determination in a laboratory. 18000.00 17000.00 Ip12 Ip11 16000.00 Ip10 Ip8 Ip9 Ip7 15000.00 Pateke-2 Ip6 14000.00 Ip5 13000.00 Ip4 Ip3 12000.00 Ip2 Amokura-1 11000.00 10000.00 Ip2 9000.00 Tui-1 Ip1 8000.00 7000.00 3000.00 5000.00 7000.00 9000.00 11000.00 TAP Contouring – top F sand depth to OWC Coordinates (m) Top F sand depth to OWC (m) X Y Low Case Mid Case High Case Tui-1 10630 9279 10 10 10 Ip1 10528 8446 7 8 9 Ip2 10871 9859 6 7 8 Amokura-1 7067 11350 12 12 12 Ip2 6683 11970 8 10 11 Ip3 6154 12450 6 8 9 Ip4 5817 13220 6 8 9 Ip5 5673 13890 8 10 11 Ip6 5625 14520 10 11 12 Pateke-2 5817 15100 13 13 13 Ip7 6250 15430 10 11 12 Ip8 6635 15770 6 8 9 Ip9 5625 15620 8 11 12 Ip10 5237 16066 6 9 10 Ip11 4693 16741 9 11 12 Ip12 3968 16904 8 10 11 OWC = oil water contact Ip = interpolated point Coordinates use a local origin TAP contouring: Mid Case – top F sand depth to OWC 18000.00 17000.00 16000.00 15000.00 14000.00 13000.00 12000.00 11000.00 10000.00 9000.00 8000.00 7000.00 3000.00 5000.00 7000.00 9000.00 11000.00 Blue contour = oil water contact (OWC) TAP 3D contouring: Mid Case – top F sand depth to OWC NOTE: 3D view has approx 1:100 vertical exaggeration Gross Reservoir Volume = (positive surface) – (OWC horizontal plane) (OWC = 0 m contour) http://www.cseg.ca/recorder/pdf/2002/11nov/nov02_07.pdf NET-TO-GROSS Ned Etris and Bruce Stewart Core Lab Reservoir Technologies Division, Calgary, Canada “Net-to-gross ratio” is one of those terms that can mean different things to different disciplines, often causing confusion and misunderstanding. So what could “net-to-gross” mean? The quick answer to some is: it doesn‟t matter; it is net pay that matters! The more helpful answer is: “It depends.” Which net and which gross is the speaker is talking about? Is it gross thickness, gross reservoir, or gross pay? To sort out the confusion, there are several terms (and combinations of terms) to understand: net, gross, thickness, pay, and reservoir. Basically, „pay‟ means rock within the hydrocarbon zone, „reservoir‟ means rock capable of flowing any fluid, including water, and „net‟ means rock that exceeds various cutoffs defined by an analyst. Put the terms together in various ways and you can get: 1) Gross thickness. This is customarily used to refer to a lithologic or sequence stratigraphic unit and doesn‟t have anything to do with fluids. It simply represents all rock between the top pick and bottom pick for a unit. 2) Net thickness. This is the total interval of reservoir quality rock within the gross thickness – that is, rock that will flow fluids. To be part of the net thickness, a rock‟s properties must exceed some defined thresholds, called cutoffs. The criteria for the establishment of cutoffs can be a complex subject by itself. 3) Gross reservoir. This means the thickness of the unit from the highest part to the lowest part that is reservoir quality, but this obviously can include tight rock (immobile fluids) inter-bedded with reservoir quality rock. Hence gross reservoir can be a subset of gross thickness. Geologists often map this instead of gross thickness, in which case it substitutes for gross thickness. 4) Net reservoir. This is the total thickness of reservoir quality rock within the gross reservoir, and is therefore identical to the net thickness defined above. It is the sum of the thicknesses of the individual reservoir quality beds within the gross unit. (Imagine distilling off the non-reservoir rock and leaving behind only the good stuff.) Although this is a more descriptive term than net thickness, it is not as widely used. 5) Gross pay. This is the thickness of rock from the highest point of hydrocarbon saturation (usually the base of the top seal of the reservoir) to the lowest point, which is not necessarily the base of the reservoir (if a hydrocarbon-water contact is present). Like gross reservoir, though, this interval may include non-reservoir and, therefore, non-net pay rock, but it is often smaller than gross reservoir because of the presence of water. (We ignore capillary pressure and transition zone effects in this article because they are a complication unnecessary for the general understanding of the terms of interest.) 6) Net pay. This is the total thickness of reservoir quality rock that will flow some amount of hydrocarbons from rock exceeding user-determined cutoffs. It is the sum of the thicknesses of the individual reservoir quality beds within the gross pay unit. (Again, imagine distilling off the non-reservoir rock and leaving behind only the good stuff, but in this case not including rock containing substantial amounts of water.) So, what does a person mean when he says, “net-to-gross ratio?” Guess what? You can‟t tell without checking the gist of the conversation, or the mapping if it is provided, because the ratio could refer to thickness or to pay! One supposes to be more informative we should say “net-to-gross thickness” and “net-to-gross pay,” but these terms are not widely used. In our experience, the most common usage of net-to-gross ratio among flow simulation engineers refers to net-thickness- to-gross-thickness, because its main use in reservoir flow simulators is to determine the volume of rock holding a mobile fluid, whether gas, oil, or water. (Flow simulators don‟t even know about the non-flowing rock that may be part of gross thickness; they ignore it. But flow simulators care about flowing water as much as about flowing hydrocarbons, because it provides critically important pressure support.) The actual volume of hydrocarbon is then determined by taking into account the hydrocarbon-water contact. By contrast, within the context of reserves calculations, net-to-gross ratio is usually the ratio of net pay to gross pay, because its main purpose is to determine the volume of hydrocarbons in place. http://www.spwla.org/library_info/glossary/reference/glosss/glosss.htm saturation (1) The fraction or percentage of the pore volume occupied by a specific fluid (e.g., oil, gas, water, etc.). The fluids in the pore spaces may be wetting or nonwetting. In most reservoirs, water is the wetting phase, but a few reservoirs are known to be oil wet. The wetting phase exists as an adhesive film on the solid surfaces. At irreducible saturation of the wetting phase, the nonwetting phase is usually continuous and is producible under a pressure gradient to the well bore. (2) The occupation of fluids in a pore may take different forms: a. Funicular saturation. A form of saturation in which the nonwetting phase exists as a continuous web throughout the interstices. The nonwetting phase is mobile under the influence of a hydrodynamic pressure gradient. The wetting phase might or might not be at irreducible saturation. In the illustration, the oil in the "A" figure is funicular b. Pendular saturation. The wetting phase exists in a pendular form of saturation. An adhesive fluid film of the wetting phase coats solid surfaces, grain-to-grain contacts, and bridges fine interstices or pore throats. The wetting phase might or might not be at irreducible saturation. In the illustration, water in the "A" and "B" figures is pendular. c. Insular saturation. A form of saturation in which the nonwetting phase exists as isolated insular globules within the continuous wetting phase. A drop in pressure might or might not cause the insular globules to collect into a continuous phase. In the illustration oil in the "B" and "C" figures is insular. http://www.npd.no/engelsk/npetrres/petres97/header.map http://www.npd.no/engelsk/npetrres/petres97/c2-rec.html Recovery factors for existing oil fields – Norwegian North Sea Of the 39 oil fields that are in production or for which an approval for development is given (resource classes 1-2), as of 31.12.96, 33 have reservoirs in sandstone. Reserves in these fields (including additional resources in Troll II), are estimated to be 2540 million Sm3 of oil. This corresponds to an average recovery factor of approximately 45%. In addition, oil reserves in 6 fields with chalk reservoirs, estimated to be 640 million Sm3 oil, have an average recovery factor of 32%. Taken together, these give an expected average recovery factor of just under 42% for all the fields in resource classes 1 and 2. If resources from the potential for improved resource exploitation, placed in classes 3-6, are also included, the average recovery factor is increased to 45%. The in place resources in the 39 fields make up 80% of the total discovered in place oil resources. Several major oil fields with sandstone reservoirs currently have a relatively high recovery factor, also in an international context. For instance the Gullfaks, Oseberg and Statfjord fields, together, have oil reserves which give an average recovery factor of just under 60%. If gas injection is used, it is expected that a few reservoirs will achieve a significantly higher recovery factor. The recovery factor for parts of the Statfjord field is expected to be as high as 74%. On the other hand, two of the large chalk fields, the Eldfisk and Valhall fields, have oil reserves whose average recovery factor is only 24%. The challenges here will consist of understanding the reservoir behaviour and of implementing measures, such as gas or water injection, to increase the recovery.