Reservoir Development Plan Research Articles

Modeling of Reservoir Compaction and Surface Subsidence at South Belridge

Summary Finite-element models of depletion-induced reservoir compaction and surface subsidence have been calibrated with observed subsidence, locations of surface fissures, and regions of subsurface casing damage at South Belridge and used predictively for the evaluation of alternative reservoir-development plans. Pressure maintenance through diatomite waterflooding appears to be a beneficial means of minimizing additional subsidence and Assuring as well as reducing axial-compressive-type casing damage.

Reservoir Management Practices

Summary This paper describes the reservoir management practices used at fieldsdeveloped and operated by Esso Production Malaysia Inc. (EPMI). The goal of EPMI's reservoir management activities is to maximize profitability andeconomical recovery of oil. Excellence in reservoir management is achieved withclearly defined and endorsed plans for management of each reservoir and acoordinated process to collect, analyze, validate, and integrate reservoirdescription and performance data into optimal development and depletion plans. Use of a multidisciplinary team to identify problems and to implement timely, innovative solutions is a key problems and to implement timely, innovativesolutions is a key ingredient. Through regular reports to management andfrequent discussions among functional groups, reservoir management objectivesand stewardship performance are communicated. Introduction Reservoir management is a significant component of EPMI's developmentplanning and production operations. Reservoir management planning, which beginsduring predevelopment phases, is emphasized throughout the productive lives ofthe reservoir and field to maximize profitability and economical oil recovery. As contractor to Petroleum Nasional Bhd. (PETRONAS), the Malaysian national oilcompany, EPMI currently operates 12 oil fields with 66 active reservoirs in the South China Sea. The fields are located within the 1976 production sharingcontract (PSC) areas (Fig. 1) about 130 to 260 km [80 to 160 miles] offshore Peninsular Malaysia. Production was initiated in 1978. By the end Peninsular Malaysia. Production was initiated in 1978. By the end of 1991, 28 platformshad been installed and developed with 755 completions. Five additionalplatforms are planned to complete development of the Seligi, Guntong, Tabu, and Dulang fields. The reservoirs in all fields except Seligi, Guntong, Tabu, and Dulang are mature, having produced more than 50% of their expected ultimaterecovery. Reservoir Types and Drive Mechanisms The major reservoirs operated by EPMI can be grouped into six types (see Fig. 2). Most major reservoirs have large associated gas caps where producedgas is reinjected for gas-cap expansion to displace oil downdip to productionwells, thereby avoiding oil losses to the gas cap. The major Groups E, J, and Ksandstones of the Bekok, Pulai, Tiong, Kepong, Semangkok, and Seligi fieldshave rim or pancake-type oil columns with large overlying gas caps and moderateto strong aquifer support. The Palas Group I sandstone is similar except thatthe aquifer support is weak because of poor rock quality and continuity in thesurrounding aquifer areas. At Irong Barat, gravity drainage with gas injectionfor pressure maintenance is the predominant drive mechanism because of the highdip angle, low solution GOR, and high permeability. Full voidage replacement bycrestal gas injection is required to avoid gas-cap shrinkage. The lower Group Jsandstone at Tinggi has strong aquifer support and no gas cap, so injection isnot required. The upper Group J sandstone, however, which is in communicationwith the lower group J sandstone, has a gas ca but weak aquifer support. Consequently, gas is reinjected. At the Tapis, Guntong, and Tabu fields, the Group I and J sandstones have weak aquifer support and long oil columns, soboth water and gas are injected to maximize recovery. Reservoir Management Goal and Key Objectives The company's reservoir management program is an ongoing, dynamic process ofcollecting, analyzing, validating, and integrating process of collecting, analyzing, validating, and integrating reservoir description data andperformance data into an optimal reservoir development and depletion plan. Thegoal of reservoir management is to maximize profitability and economicalrecovery of hydrocarbons. To achieve that goal, the following three keyobjectives were established.Mitigation of production decline in existingfields. With the mature fields exhibiting a decline in productive capacity ofmore than 15%/yr, capacity enhancement is a key requirement. Several programsimplemented to mitigate decline are discussed later.Aggressive pursuit ofnew field development. The recent work completed to confirm and implementdevelopment plans for the North Seligi resource potential illustrates theapproach used.Effective exploration and exploitation of new acreage. Withthe current exploration activities in the PM-5 and PM-8 PSC areas, new acreageis being exploited effectively, but these activities are not discussed in thispaper. Reservoir Management Process Reservoir management practices are initiated before development work beginsand continue throughout the life of the reservoir through the process shownschematically in Fig. 3. JPT P. 1296

Review of the Means San Andres Unit CO2 Tertiary Project

Summary A full-scale CO2 miscible tertiary project in the Means San Andres Unit, Andrews County, TX, is expected to result in the additional recovery of morethan 38 million STB [6.0 × 10(6) stock-tank m3]. Design, implementation, surveillance, and early performance of the CO2 project are discussed. Introduction The tertiary flood implemented in the Means San Andres Unit was part of anintegrated reservoir development plan that included apattern-modification/infill-drilling program and construction of newfacilities. The 10-acre [4-ha] infill program consisted of drilling 205producers and 158 injectors in the project area. Facility construction includedCO2 injection and production facilities and a gas compression and treatingfacility to recycle the produced CO2/gas stream. CO2 injection began in Nov.1983. Unique aspects providing engineering and operational challenges in thisproject include a more viscous crude than is found in most west Texas CO2projects, a relatively high miscibility pressure. and a narrow window betweenoperating pressure and the bottomhole formation parting pressure. Field Discovery and Development The Means (San Andres) field is about 50 miles [80 km] northwest of Midlandin Andrews County, TX. Geologically, the field lies along the eastern edge ofthe central basin platform and in a northwest/southeast trend of Permian SanAndres fields. Production is from the Grayburg and San Andres formations atdepths ranging from about 4,200 to 4,800 ft [1280 to 1460 m]. The Meanstertiary target is the San Andres. which consists of dolomite with minoramounts of shale and anhydrite. The field is a north/south-trending anticlineseparated into north and south domes by a dense structural saddle near thecenter of the field (Fig. 1). Table 1 gives reservoir and fluid properties forthe San Andres. Most significant is the oil viscosity of 6 cp [6 mPas], compared with 1 to 2 cp [1 to 2 mPas] for most San Andres reservoirs in westTexas. The primary producing mechanism was a combination of fluid expansion anda weak waterdrive. In 1963, the field was unitized and water injection beganinto a peripheral waterflood pattern. CO2 Project Planning/Design A review of other proposed CO2 projects indicated that, although Means wassimilar to other large San Andres fields in the area, some reservoir and fluidproperties appeared unique or at least substantially different. Programs weredesigned to evaluate the impact of high oil viscosity, relatively highmiscibility pressure, and low formation parting pressure. The initial screeningstudies indicated that the miscible CO2 process would work despite potentialproblems associated with these reservoir properties. Fieldwide implementationplans proceeded simultaneously with these investigations. Process Characterization. Investigations characterizing the CO2 floodprocess for Means were important in identifying the tertiary oil target, conducting miscible simulation studies, and designing the CO2 flood. Laboratorytest results, combined with actual field data, were used to determine minimummiscibility pressure (MMP), residual oil saturation (ROS) to waterflood, andthe ability of CO2 to mobilize the waterflood residual oil. Operating pressureis more important at Means than in many Permian Basin CO2 projects because ofthe small window between MMP and formation parting pressure. Slim-tubeexperiments indicated that the MMP was between 1,850 and 2,300 psi [12.8 and15.9 MPa], Because of the slim-tube data and the bottomhole injection pressurelimitation of 2,700 to 2,800 psi [18.6 to 19.3 MPa] caused by a low formationparting pressure, a 2,000-psi [13.79-MPa] operating pressure was selected. Anestimate of waterflood ROS was needed to determine the magnitude of thetertiary target. Relative permeability data, remobilization tests, and pressurecore results indicated that the 34% ROS determined from the pressure cores wasthe most representative. Remobilization tests to determine the ability of CO2to mobilize waterflood residual oil were run with Means crude and native-statecomposite cores. Many authors have reported observance of water blocking in thelaboratory. After the core was water-flooded, CO2 and water were injected at2,300 psi [15.9 MPa] at a water-alternating-gas (WAG) ratio of 1:1 until themiscible residual saturation of 9.1 % was reached. JPT P. 638⁁

Use of Integrated Reservoir Description in Upper Wolfcampian Carbonate, Midland Farms Deep Unit, Andrews County, Texas--Example of Effective Teamwork: ABSTRACT

A cooperative geological-engineering evaluation of cores, core data, well logs, and production data made it possible to rapidly determine net pay limits, calculate original oil in place and recovery factors, and formulate reservoir development plans. The resulting detailed reservoir description and performance characterization of upper Wolfcampian fossiliferous and oolitic limestones were used successfully to optimize an existing waterflood operation and to initiate an additional waterflood program. Geologic input consisted of (1) identifying lithostratigraphic zones in cores that are also recognizable on well logs, (2) interpreting depositional environments, (3) documenting the origins and vertical distribution of pore types, and (4) identifying and correlating individual reservoir units. Engineering input consisted of (1) identifying the productive strata, (2) determining net pay criteria, and (3) mapping net pay.

Development Planning and Management of Petroleum Reservoirs Using Tank Models and Nonlinear Programming

This paper demonstrates the feasibility of applying generalized reduced gradient nonlinear programming methods to solve optimal control models for petroleum reservoir development planning and management. The objective of the models is to maximize present value of profits, and their decision variables are how many wells to drill in each time period, the production rates, abandonment time, and platform size. The analysis uses tank-type reservoir models to describe the reservoir dynamics, and models both a gas reservoir with water drive, and a three phase oil reservoir. Results of several case studies on each model are presented. Extensions that consider spatial variation in the reservoir and use grid reservoir models are being investigated.