Adjustment to Oil Saturation Estimate Due to Various Reservoir Drive Mechanisms

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1 Cloud Publications International Journal of Advanced Petroleum Engineering and Technology 2014, Volume 1, Issue 1, pp , Tech-316 Research Article Open Access Adjustment to Oil Saturation Estimate Due to Various Reservoir Drive Mechanisms Okotie Sylvester 1 and Ikporo Bibobra 2 1 Department of Petroleum and Gas Engineering Federal University of Petroleum Resources, Effurun, Nigeria 2 Department of Chemical and Petroleum, Niger Delta University, Omasoma, Nigeria Correspondence should be addressed to Okotie Sylvester, sterz_ok@yahoo.co.uk; bblaye2@yahoo.com Publication Date: 20 November 2014 Article Link: Copyright 2014 Okotie Sylvester and Ikporo Bibobra. This is an open access article distributed under the Creative Commons Attribution License, which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited. Abstract Fluid distribution in the reservoir is an important factor when planning for an oil and gas field development but cannot be done without saturation values within the reservoir. It must also be carefully monitored to optimize reservoir management, and delay gas or water coning. As fluid is produced from the reservoir, the saturation value changes depending on the nature of the drive mechanism, leaving some oil in un-drained compartments called residual oil. Recovery of this residual oil is at present a big challenge for many oil companies and there is a continuous search for a cheap and efficient technology that can help in its recovery. Hence, developed in this study is software SATEST to estimate the adjustment to oil saturation due to the various reservoir drive mechanisms and also validated with a commercial tool MBal. Result obtained showed a difference of 0.22% on average. Keywords Drive Mechanisms; Fluid Distribution; Field Development Plan; Saturation; Residual Oil Saturation; Rock Wettability; Oil Recovery 1. Introduction Saturation, defined as a fraction of oil, gas, water and other fluids in the porous rock body is a crucial factor when evaluating the formation. Without saturation values, fluid distribution cannot be evaluated and no informed decision can be made on the development of an oil or gas reservoir. Hence, oil saturation helps reservoir engineers to maximize production and improve total recovery which implies that the most fundamental reservoir parameters such as oil, gas and water content are critical factors in determining how each oil field should be developed. More so, Saturation changes are critical to fluid flow and must be carefully monitored to optimize reservoir management, and delay gas or water coning (Jean- Louis et al., 1996)

2 In the initial estimation of the oil and gas in place, porosity, hydrocarbon saturation, the thickness of the reservoir rock and the real extent of the reservoir determines the total hydrocarbon volume in place. This is usually determined by volumetric method and; an average value of water saturation is gotten from core analysis or well log. Tarek Ahmed (2001) stated that a proper averaging of saturation data is required and this saturation value should be weighted by both the interval thickness h i and interval porosity Ø i. The average saturation of each reservoir fluid is calculated using the following equation. At this point, we should note that the water bound to the shale is not included in this estimation of saturation, which implies that shale corrections must be performed if shale is present in the reservoir sand (Crain). The focus of this study is on the changes in the saturations observed as fluid is produced from the reservoir as a result of difference in drive mechanisms. The concept is developed by combining the material balance equation, MBE with the saturation equation. Thus, a clear understanding of the saturation distribution in the reservoir is critical to a successful field development. This is to say that the reservoir engineer constantly seeks for ways to optimally recovery the hydrocarbon from the reservoir in a cost effective manner to prevent oil being trapped in the reservoir during primary and secondary recovery due to the heterogeneous nature of formations. 2. Saturation Distribution in Reservoirs When a pool of oil is discovered, it sounds very interesting to the geologists and reservoir engineers who evaluates the prospect and more importantly to the company who owns the block. Initially to them, it looks like the rock body is filled with large bubbles of this oil, but on the contrary in reality, the oil and gas in the reservoirs is actually distributed through the pore space between carbonate or sand grains in the reservoir layers as depicted in Figure 1a and 1b. Figure 1a: Oil Saturation in the X Reservoir Model Figure 1b: Clear View of Oil Saturation International Journal of Advanced Petroleum Engineering and Technology 18

3 In reservoirs, the equilibrium fluid saturation distribution is governed by the portion of fluid in the pore space characteristics in best practice between 25% and 35% of total volume prior to production ( Jean- Louis et al., 1996). This fraction is not completely filled with a particular fluid only but with all fluids present in the reservoir in different proportions which changes throughout the life of the reservoir. Measurably, in the reservoir, the fluid saturations (So, Sg and Sw) varies with space, most notably from the water-oil contact to the reservoir top (see Figure 1a, 1b and 2a, 2b), and time during the production phase. In fact, different parts of the reservoir may have different fluid saturations and the saturation in any elementary volume of the reservoir changes progressively during the production. This implies that, as oil is produced from the reservoir, the volumes that each fluid occupies will be altered considerably. This research intends to account for the changes due to water influx, gas expansion and a combination drive because nature avoids vacuum. Therefore, when performing prediction on the total reservoir behavior, the expansion of the reservoir liquids and gases cannot be neglected. Furthermore, during the drainage process, hydrocarbon entering pore spaces initially occupied by the wetting fluid, usually water, during migration of hydrocarbons from a source rock into a reservoir trap. A pressure differential is required for the non-wetting phase to displace wetting phase and this is equivalent to a minimum threshold capillary pressure that is dependent on pore size but will not be considered in this study. 3. Problem Definition The initial oil in place determined from the MBE is referred to as the effective or active initial oil in place, and is usually smaller than the volumetric estimate due to oil trapped or bypassed in un-drained fault compartments or low-permeability regions of the reservoir. Also, additional recovery from residual oil can lead to increase in global oil production and extend lives of many oilfields. This is not always the case because the recovery of this bypassed oil residual oil is currently a big challenge to many oil companies. 4. Technical Objectives The focus of this study is to estimate the changes in saturation observed as fluid is produced from the reservoir to account for the changes due to water influx, gas expansion and a combination drive since nature avoids vacuum. Aims are: To maximize production and improve total recovery in a cost effective manner To delay gas or water coning To aid the success of field development study 5. Methodology Derive the oil saturation equation for the different reservoir drive mechanisms Develop a user friendly software SATEST using visual basic dot net frame work. The estimation incorporated in the design is a combination of the various drive mechanisms with saturation equation. The result obtained from SATEST was compared with MBal. International Journal of Advanced Petroleum Engineering and Technology 19

4 6. Nature of Reservoir Rock Wettability In every hydrocarbon reservoir, there are two phases existing in the rock body, these are the wetting and non-wetting phase. Most oil and gas reservoirs are water wet; water coats the surface of each rock grain. A few reservoirs are oil wet, with oil on the rock surface and water contained in the pores, surrounded by oil. Some reservoirs are partially oil wet. Oil wet reservoirs are very poor producers as it is difficult to get the oil to detach itself from the rock surface. In a water wet reservoir, the water is held in place by surface tension. The surface water does not move while the oil or gas is being produced. This situation is shown below. Figure 2a: Water Wet Reservoir Figure 2b: Oil Wet Reservoir 7. Concept of Drive Mechanism on Oil Saturation Production of oil or gas will often change the water saturation which in turn affects the oil and gas saturation, but the amount of change varies with the drive mechanism. In an aquifer drive reservoir on an efficient water flood, as the oil is produced to the surface facilities via the production tubing, the water saturation increases accordingly to fill the space previously occupied by the oil withdrawn (Figure 3b). Also, in the case of gas cap drive reservoir (Figure 3a), the gas being occupied at the upper part of the reservoir, pushes the oil down, but in this case, the water saturation does not change until the gas that replaced the oil is also produced. If there is no aquifer support, there will be no adjustment to oil saturation since both situations produce only by expansion drive also called solution drive which is produced by dissolve gas in the oil. Hence, in this case water saturation does not change unless a water flood is imposed by the field operator. International Journal of Advanced Petroleum Engineering and Technology 20

5 S gi Gas Cap Original GOC S gi Gas Cap Original GOC S org S oi Oil expansion OWC Aquifer S o Oil expansion OWC Aquifer Present GOC Oil saturation adjustment due to gas expansion Figure 3a: Oil Saturation Adjustment Due to Gas Expansion Gas Cap GOC Gas Cap GOC S oi Oil expansion S o Oil expansion Present OWC S orw Original OWC Aquifer Aquifer Original OWC Oil saturation adjustment due to water influx Figure 3b: Oil Saturation Adjustment Due to Water Influx 8. Residual Oil Saturation, Sor In most cases, during the process of displacing the oil from the porous media by secondary recovery (water or gas injection) there will be some remaining oil left that is quantitatively characterized by a saturation value (residual oil saturation) which is larger than the critical oil saturation defined as the saturation of the oil which must exceed a certain value and at this particular saturation, the oil remains in the pores and, for all practical purposes, will not flow. International Journal of Advanced Petroleum Engineering and Technology 21

6 The term residual saturation is usually associated with the non-wetting phase when it is being displaced by a wetting phase which is a concern to reservoir engineers. Also, while additional 15-25% can be recovered by secondary methods such as water injection leaving behind about 35-55% of oil as residual oil in the reservoirs (Cosse, 1993). This residual oil is usually the target of many enhanced oil recovery technologies and it amounts to about 2-4 trillion barrels (Hall et al., 2003) or about 67% of the total oil reserves, (Bryant et al., 1993) Oil Saturation 8.2. Oil Saturation Adjustment Due to Gas Cap Expansion The volume of oil in the gas-invaded zone is represented as 8.3. Oil Saturation Adjustment Due to Water Influx The volume of oil in the water-invaded zone is represented as: International Journal of Advanced Petroleum Engineering and Technology 22

7 8.4. Oil Saturation Adjustment Due to Combination Drive 8.5. Comparing Result Obtained with SATEST and MBal SATEST is a tool (see system option screen in Figure 4) developed in this study to determine the level of oil saturation as production declines. Data given in the appendix section from an XY reservoir was used and the result obtained was validated with MBal as shown in the Table 1. The enegry plot (Figure 6) shows that the reservoir is strongly supported by an aquifer. Thus, in SATEST, an adjustment option due to water influx was selected to estimate the oil saturation and when validated with MBal gave a close value (Figure 5). Table 1: Saturation Result of XY Reservoir Time (Month) Pressure (psia) Oil Saturation (SATEST) Oil Saturation (Mbal) Difference in Saturation International Journal of Advanced Petroleum Engineering and Technology 23

8 Figure 4: SATEST System Option Screen Figure 5: Comparing SATEST and MBal Result International Journal of Advanced Petroleum Engineering and Technology 24

9 Figure 6: Energy Plot 9. Conclusion It should be noted that the value of the initial oil in place as determined from the material balance is referred to as the effective or active initial oil in place. This value is usually smaller than that of the volumetric estimate due to oil being trapped in un-drained fault compartments or low-permeability regions of the reservoir. Since oil saturation is a key parameter in oil field development, management of producing oil and gas companies seek to recover the remaining oil in place and the bypassed oil after a Waterflooding project in a cost effective way. At some point in the oil production from the reservoir, a study is usually carried out to determine the present oil saturation in the reservoir. Hence, SATEST software developed in this study can be used to estimate fraction of oil in the pore space oil saturation as the reservoir declines. References Bryant, R.S., Stepp, A.K., Bertus, K.M., Burchfield, T.E., and Dennis, M. Microbial Enhanced Waterflooding Field Pilots. Dev. Pet. Sci ; Cosse, R., 1993: Basics of Reservoir Engineering. Editions Technic, Paris Crain, E.R. Lecture Note on, Water Saturation Basics. Online Petrophysical Handbook. Hall, C., Tharakan, P., Hallock, J., Cleveland, C., and Jefferson, M. Hydrocarbons and the Evolution of Human Culture. Nature ; Jean-Louis Chardac, Mario Petricola, Scott Jacobsen and Bob Dennis. In Search of Saturation Middle East Well Evaluation Review. International Journal of Advanced Petroleum Engineering and Technology 25

10 Tarek Ahmed. 2006: Reservoir Engineering Handbook. 3rd Edition. Oxford, Elsevier Appendix A Table A1: Rock and Fluid Properties Reservoir Rock and Fluid Properties GOR 550scf/STB Pi 3880 psig Oil gravity 46API phi 0.28 gas gravity Swc water salinity ppm N 298MMSTB T 280 deg F prod start date 1/1/1998 Pb 2200psig h 275 ft Bob rb/STB k 220 md oil vis 0.54 cp Table A2: Production Data Time Pressure Np Wp We Bo Bgi Bw (rb/stb) (month) (psia) (MMSTB) (MMSTB) (MMSTB) (rb/stb) (cuft/scf) International Journal of Advanced Petroleum Engineering and Technology 26