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Petroleum reservoir management is a dynamic process that recognizes the uncertainties in reservoir performance resulting from our inability to fully characterize reservoirs and flow processes. It seeks to mitigate the effects of these uncertainties by optimizing reservoir performance through a systematic application of integrated, multidisciplinary technologies. It approaches reservoir operation and control as a system, rather than as a set of disconnected functions. As such, it is a strategy for applying multiple technologies in an optimal way to achieve synergy. Reservoir management has been in place in most producing organizations for several years.
This page provides several reservoir management case studies that illustrate carbonate reservoirs in which waterflooding and miscible gas injection techniques have been implemented. This field produces primarily from a Jurassic-age limestone-dolomite section that has a simple plunging anticline structure. The updip trap is formed by a combination of facies change from dolomite to dense limestone and a bounding fault. The formation is layered and has been divided into 18 correlative zones. The field was developed competitively by several operators.
Miscible injection is a proven, economically viable process that significantly increases oil recovery from many different types of reservoirs. Fieldwide projects have been implemented in fields around the world, with most of these projects being onshore North American fields. Many of these projects are quite mature, making the recovery and production-rate benefits well established. As a result, the ability to predict recovery levels, rate improvements, costs, and resulting economics can now be considered proven and reliable. The purpose of this chapter is to introduce some fundamental concepts about miscible displacement, suggest some methods of predicting the benefits of miscible injection, and present a few field examples that demonstrate what has been accomplished with miscible injection. The schematics at the bottom of Figure 1.3 illustrate the pore-level recovery mechanisms discussed earlier (Figure 1.2). At the end of the waterflood, residual oil is a discontinuous phase that occupies approximately 40% of the pore space. Early in the miscible flood [3.0 to 3.5 total pore volumes (PV) injected], some of this oil has been miscibly displaced by solvent from the higher-permeability flow path (on the pore scale). However, some oil also has been initially bypassed by solvent. Note that this bypassing at the pore level is much different from solvent bypassing, which can occur at the field scale because of larger-scale reservoir heterogeneities. As depicted in the schematic corresponding to late in the flood (to 7.0 total PV injected), part of this locally bypassed oil is subsequently recovered by extraction and swelling that takes place as solvent continues to flow past the bypassed oil. In this case, approximately 30% of the total amount of oil recovered by the CO2 flood was recovered by extraction and swelling. After Jerauld (solid lines are the reference model, and dashed lines are the scaleup model). In field projects in which the displacement was above either the MMP or the MME, residual oil saturation determined by coring behind the solvent front varied from approximately 3 to 10% PV.
Wilkinson, J.R. (ExxonMobil Production Company) | Genetti, D.B. (ExxonMobil Production Company) | Henning, G.T. (ExxonMobil Production Company) | Broomhall, R.W. (ExxonMobil Exploration Company) | Lawrence, J.J. (ExxonMobil Upstream Research Company)
Abstract Some of the key challenges facing producing organizations are to increaserecovery from existing fields and to optimize the utilization and value ofexisting infrastructure. The Middle East is uniquely positioned to help supplyworld energy demand through efficient application of secondary and tertiaryrecovery techniques in super-giant carbonate reservoirs. Three long-lifecarbonate fields in the USA are offered as examples of the benefits achieved bya continuous process of data collection, studies, and systematic application ofavailable technologies. This continuous process has progressively increasedultimate recovery. The example fields will achieve a range of incrementalincreases in the recovery factor of between 8 and 20 percent originaloil-in-place (% OOIP) or up to 50% OOIP increase over conventional primaryrecovery. A systematic and integrated approach to reservoir management has beenemployed to understand the basic rock and fluid physics of each reservoir andthe key parameters that impact performance. The development plan for each ofthe example fields has then been implemented in a way that maximizes bothhydrocarbon recovery and value of the assets while utilizing best availabletechnologies.The Jay Field, in the southeastern United States is a deep, heterogeneous, carbonate that was discovered and put on production in the1970's. The field is geologically complex, including cemented zones associatedwith stylolites that restrict vertical flow. Using sophisticated3D-geostatistical models and advanced reservoir simulation, we were able tooptimize the performance of both a waterflood and a miscible nitrogen (N2)flood over the field life. As a result, we expect to achieve a recovery of morethan 60% OOIP. Currently, the field has produced over 50% OOIP. The Salt Creek Field in West Texas is a carbonate that provides anexample of the benefits of successive implementation of infill drilling andimproved recovery processes to increase recovery. Acquired in the late 1970's, the field was the subject of two infill-drilling programs and development of aflank residual oil zone (ROZ). Studies were conducted to balance injection andwithdrawal and to better understand the complex stratigraphy. The field isexpected to achieve a recovery factor of greater than 60% OOIP using a carbondioxide (CO2) water-alternating-gas (WAG) process. Currently, the field hasproduced over 50% OOIP. The Means Field in West Texas is a carbonate with low permeabilityand high viscosity oil and an underlying aquifer. An infill-drilling program, improved waterflood, and a CO2 WAG flood in a portion of the fieldsignificantly increased recovery. The field is expected to achieve a recoveryfactor of about 45% OOIP within the CO2 project area. Currently, thefield has produced over 30% OOIP. Lessons learned are summarized and a process is recommended to address thechallenges of improving recovery from similar Middle Eastern carbonatefields. Parameters Controlling Recovery ExxonMobil has established a large knowledge base of secondary and tertiaryproject experience at the laboratory, pilot-test, and field implementationstages. Projects include waterfloods, immiscible and miscible gas injection forsecondary oil recovery, tertiary WAG, foam-assisted WAG, and re-injection ofsour or acid gas for both oil recovery and sulfur/CO 2 disposal.
Abstract The need to enhance recovery from the vast amount of remaining oil- and gas-in-place in the carbonate reservoirs requires better reservoir management practices. Proper timing has a profound effect on the implementation of sound reservoir management technology on recovery efficiency. With this in mind, our goal should be to maximize volumetric sweep early in the project's life. Trying to squeeze more oil from marginal projects will generally yield marginal to average results. The purpose of this paper is to:identify the major attributes of a successful waterflood asset management program, outline critical issues and technical areas, and document benefits received from a team approach to asset management, utilizing carbonate reservoir case studies. P. 699