During the late 1990's, Exxon and Mobil had each independently developed next-generation reservoir simulation systems. Both next-generation systems embodied a substantial number of step-out simulation technologies, which were extremely complementary. ExxonMobil moved aggressively to combine the best of both companies’ technologies into one industry-leading simulation system called EMpower™. This new simulation system is now being used to actively manage ExxonMobil's global resource base. Key features of this industry-leading simulator are described in this paper. The new simulator employs unstructured grids to more accurately model complex geologic features, near-wellbore flow, and aquifer support. Algorithms for optimal layering and flow-based scale-up on unstructured grids are tightly integrated in the EMpower system. The computations are performed within the unstructured grid fabric. Interactive simulation ties together the geologic and reservoir simulation models with production data yielding high-confidence forecasts of future performance. Emphasis is on minimizing the overall turnaround time between formulation of the simulation problem and generation of results. A comprehensive graphical user interface provides reservoir engineers and geoscientists of all skill levels with easy access to reservoir simulation. The user interface is designed to facilitate the full range of simulation problems—from quick screening studies to large, complex field models. The geoscience and reservoir engineer communicates to the executing simulation through the user interface, thereby allowing simulation progress/results to be monitored, paused, terminated, and/or restarted on command. Results are viewed within the user interface using spreadsheets, charts, or full 3D visualization. The object-oriented design of the new simulator is very flexible. The reservoir flow model is tightly integrated with the well and surface facility models for accurate, smoothly running simulations. Execution of complex well management strategies is specified in an intuitive, graphical format. For added efficiency, the simulator also is designed to take advantage of computing hardware that utilizes multiple parallel processors. The capabilities of this next-generation simulation system are demonstrated through a field study involving complex geologic features (e.g. non-vertical faults and stratigraphic pinchouts) and multiple reservoirs connected to a common production infrastructure. Introduction Reservoir simulator development has historically been an active area of internal research and development at both Exxon and Mobil.1–6 During the late 1990's, Exxon and Mobil each independently developed next-generation reservoir simulation systems. Both next-generation systems employed a substantial number of step-out simulation technologies, which were extremely complementary. ExxonMobil moved aggressively to combine the best of each company's technologies into one industry-leading simulation system called EMpower. This new simulation system is now being used to actively manage resources within ExxonMobil's global asset base. This paper describes the EMpower simulator and some of its key features. Potentially the most significant innovation adopted in the new simulator is unstructured gridding, with computations performed within the unstructured grid. A number of researchers have contributed to developments in unstructured gridding over the past two decades7–9. However, industry generally has been reluctant to apply this capability to practical reservoir simulation due in part to concerns about potential loss in computational efficiency.

Summary This paper describes the use of core analysis data, both routine and special, in characterizing the Brent Group reservoirs in the U.K. North Sea. The results of various special ore analysis tests conducted over the years indicate that coring fluid, core preservation, and laboratory procedures are important in defining relative permeability and capillary pressure. Examples are given of (1) the effect of oil-based mud filtrate on rock wettability; (2) the effect of extraction, drying, and test procedures on laboratory waterflood performance; and (3) variation of relative permeability arnong facies. Results also suggest how petrography may be used in assigning relative permeabilities by facies. Analysis of routine core data shows complexity within the Brent Group reservoirs even within relatively "uniform" sands. This is reflected by large differences in relationships between porosity and permeability. Examples are presented of such differences from well to well within the same area of a field, within the same formation in a single well, and between the oil and water zones. Examples are given of the potential to correlate these differences with log responses. Such a correlation could predict permeability variation in uncored wells more accurately. A technique to identify different porosity/permeability relationships within a well is presented. Introduction Esso E&P U.K. has an interest in several North Sea oil fields that produce from the Brent Group sands of Middle Jurassic age. These fields include Brent, Cormorant, Dunlin, Eider, Tern, and Osprey. These fields, which are opened by Shell U.K. E&P, are located in approximately 500 ft of water in the North Viking graben, 100 miles northeast of the Shetland Islands (Fig. 1). The Brent Group contains five formations representing a transgressive/regressive depositional sequence. The major regressive phase comprises a fluviodeltaic system. The section is illustrated by the type log in Fig. 2, which also illustrates the stratified nature of the sands and the permeability contrast. The depositional sequence, starting from the base and progressing upward, includes a transgressive lag depos it (Broom), prodelta shales and lower to upper shoreface sands (Rannoch), a beach and barrier bar complex (Etive), fluvial and lagoonal sediments (Lower, Middle, and Upper Ness), and a transgressive marine sand (Tarbert). The Tarbert and Ness sandstones generally are quartzose while the Etive, Rannoch, and Broom are quartzofeldspathic. Diagenesis is evidenced by the presence of kaolinite and illite along with pore-throat reduction resulting from compaction and quartz overgrowth. The conversion of feldspar to kaolinite is more widespread in the lower formations with further conversion to illite occurring in deeper areas. A more detailed description of the geology of the Brent Group is contained in Ref. 1. The need for accurate reservoir characterization is important, not only because of the geologic complexity but also because of the field development methods, which often involve concurrent waterflooding of the entire section with a limited number of fully perforated producers and injectors. In this situation, reservoir behavior is a function of many different reservoir characteristics. For example, the early appearance of water in producing wells may be caused by inefficient displacement resulting from unfavorable relative permeability relationships, severe water underrunning resulting from an adverse permeability profile within a major sand, or rapid water advance through a sand with very high permeability. A good understanding of the reasons for specific reservoir behavior is important in identifying proper remedial action. Good core coverage and full use of the resulting core data are required to manage the complex reservoirs of the Brent Group. Special Core Analysis Esso has conducted considerable special core analyses for Brent Group reservoirs, primarily in the measurement of relative permeabilities, kr; capillary pressures, Pc; and remaining oil saturations (ROS's). Special attention has been given to preservation of wettability because of its influence on these measured properties. This work has supplemented the significant amount of special core analysis undertaken by Shell. Coring Fluids. The routine use of oil-based mud to drill deviated wells from North Sea platforms presents a potential problem for special core analysis studies because such muds may alter the wettability of the reservoir rock.2,3 Tests have been performed to evaluate the effects of coring fluids on special core analysis results. Fig. 3 shows the results from tests on core plugs from the Brent field, conducted to evaluate an oil-based mud being considered for a coring program. Because preserved core material was not available, the plugs were resaturated with oil and water. The brine-saturated core plug was centrifuged to a low brine saturation, saturated with oil, and allowed to imbibe brine spontaneously (Step 1). The water saturation during imbibition increased by 40 saturation units. After the sample was returned to a low brine saturation, it was flushed with oil-based mud filtrate and aged for 4 days. The filtrate was then displaced with refined oil and the plug was immersed in brine (Step 2). This time, little water was imbibed; water saturation changed by less than 5 saturation units. The apparent wettability alteration was confirmed by waterflooding the plug to a low oil saturation and then allowing it to imbibe oil spontaneously (Step 3). Coring Fluids. The routine use of oil-based mud to drill deviated wells from North Sea platforms presents a potential problem for special core analysis studies because such muds may alter the wettability of the reservoir rock.2,3 Tests have been performed to evaluate the effects of coring fluids on special core analysis results. Fig. 3 shows the results from tests on core plugs from the Brent field, conducted to evaluate an oil-based mud being considered for a coring program. Because preserved core material was not available, the plugs were resaturated with oil and water. The brine-saturated core plug was centrifuged to a low brine saturation, saturated with oil, and allowed to imbibe brine spontaneously (Step 1). The water saturation during imbibition increased by 40 saturation units. After the sample was returned to a low brine saturation, it was flushed with oil-based mud filtrate and aged for 4 days. The filtrate was then displaced with refined oil and the plug was immersed in brine (Step 2). This time, little water was imbibed; water saturation changed by less than 5 saturation units. The apparent wettability alteration was confirmed by waterflooding the plug to a low oil saturation and then allowing it to imbibe oil spontaneously (Step 3).

In reservoirs with favorable rock and fluid properties, application of gas injection processes can enhance the recovery efficiency and value of a field development. ExxonMobil employs a systematic approach to evaluating and selecting recovery processes during the full life-cycle of each reservoir. Once a gas injection project has been implemented, ongoing surveillance programs and optimization studies are performed to ensure that maximum value is obtained from the resource. One important aspect of managing these resources has been the use of reservoir flow modeling to understand performance expectations and to develop reservoir management strategies to optimize recovery. Because ExxonMobil's experience with reservoir simulation of gas injection processes has covered many types of injection processes over many years, a full suite of simulation approaches has been used for reservoir flow modeling. The gas injection processes studied and implemented have included miscible floods, immiscible floods, Water-Alternating-Gas (WAG) floods, as well as gas disposal. A full range of injection gases such as CO2, H2S, N2 and hydrocarbon injectants has been used. The fit-for-purpose simulation approach is chosen based on specific needs and objectives for each reservoir. The approaches have ranged from coarsely-gridded black oil simulation to finely-gridded compositional simulation depending upon the specific requirements for a given field. In recent years, the emphasis has been on state-of-the-art compositional simulation. ExxonMobil has applied compositional simulation to design and manage more than 25 gas injection projects covering the full range of injectants and lithologies. Because each gas injection project is unique, the evaluation of benefits must be comprehensive and adaptable. Case studies are presented illustrating a range of gas injection processes and reservoir types. The case studies highlight important aspects of data collection, issue identification, simulation technique evaluation, process evaluation, and long-term project stewardship. Depletion Strategies Utilizing Gas Injection Injection of either hydrocarbon or inert gases is employed in reservoirs where a favorable combination of pressure, fluid properties, and reservoir characteristics result in gas being preferred versus water injection. ExxonMobil participates in over one-third of worldwide gas injection enhanced oil recovery projects and therefore has established a large knowledge base of gas injection project experience at the laboratory, pilot test, and field implementation stages. Projects in which ExxonMobil participates include gas cycling for condensate recovery, immiscible and miscible gas injection for secondary oil recovery, tertiary WAG and foam-assisted WAG projects, and re-injection of sour gas for both oil recovery and sulfur/CO2 disposal. The key factors that impact performance of gas injection projects are reservoir pressure, fluid composition, reservoir characteristics, and relative permeability. Reservoir Pressure Pressure is a key parameter in determining whether or not the injected gas will be miscible with the in-situ oil that will be contacted in the reservoir. Oil recoveries for gas injection processes are usually greatest when the process is operated under conditions where the gas can become miscible with the in-place oil. The gas and oil can be first contact miscible or develop multi-contact miscibility by extracting light components from the oil (the "vaporizing" gas drive process), and/or by losing components to the oil (the "condensing" gas drive process). Miscibility can be achieved either by managing the reservoir pressure and/or by changing the composition of the injected gas by addition of either heavier hydrocarbons or acid gas components. Gas injection can also be used to immiscibly displace oil and for reservoir pressure maintenance. Also, because gas injection will require compression, the pressures of both the source gas and the receiving reservoir are important for facilities cost and design reasons.

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Introduction In order to more accurately predict reservoir performance in the Ghawar field, an extensive performance in the Ghawar field, an extensive program of reservoir description is underway by program of reservoir description is underway by means of cores, logs and well testing. A logical extension of this effort is to investigate interwell reservoir properties by multiple well transient pressure tests. A series of reservoir pulse tests was conducted and the results pulse tests was conducted and the results indicate that this reservoir description technique is feasible over inter-well distances normally encountered in the developed areas of Ghawar. Observed time lag ranged from 0.37 to 0.60 days and pressure pulse response amplitudes ranged from 0.42 to 1.66 psi. In past reservoir modeling efforts we have noticed that, in general, significantly higher transmissibilities are required to match pressure history than are deduced from either single well pressure tests or core analysis. One possible pressure tests or core analysis. One possible reason for this could be that the reservoir has anisotropic permeability. The first pulse test series was configured such that we could analyze the results for possible directional permeability. The test area consisted of three permeability. The test area consisted of three pulsed wells forming approximately an equilateral pulsed wells forming approximately an equilateral triangle with an observation well in the center (see Figure 1), and is located in the central part ('Uthmaniyah) of the Ghawar field. Background The pulse testing technique described by Johnson, et al, was selected for application in Ghawar field under conditions of high reservoir permeability and wide well spacing. Other similar permeability and wide well spacing. Other similar testing techniques have been developed and are noted or summarized in Reference 3. This reservoir description technique is a special type of interference test in which a sequence of short duration pressure pulses or disturbances are created in a pulsing well by a series of shut-ins and are recorded in a nearby observation well. This series of pulses makes it easier to detect the arrival of the disturbance at the observation well. Figure 2 depicts schematically the creation of pulses in a producing well by a series of shut-ins. Terminology associated wily the test are indicated. The hypothetical pressure response at an observation well is shown in the lower schematic. Each response to changes in the pulsing well is characterized by two quantities: pulsing well is characterized by two quantities: the pulse Response Amplitude and the Time Lag. The Time Lag is the interval between the end of a pulse in the pulsing well and the point of maximum pulse in the pulsing well and the point of maximum response to that pulse in the observation well. The Response Amplitude is determined in the manner shown in the schematic. Each pulse and inverse (or odd) pulse is characterized in this manner. The main objectives of using the pulse test were to determine the feasibility of using this technique in Saudi Arabian oil reservoirs which have high transmissibilities and well spacing in excess of one kilometer, and to investigate the possible existence of directional permeability. possible existence of directional permeability. The location for the first pulse test was selected to minimize the effects of wide well spacing and free gas saturation, which are two factors that are unfavorable to successful pulse testing. The test site is shown in Figure 1. The three pulsing wells are located slightly over one kilometer from the central observation well. Reservoir pressure in this area has always been above the saturation pressure of approximately 1900 psi, thus eliminating any presence of a small free gas saturation which would increase reservoir compressibility. The wells that were pulse-tested produce from the Arab-D reservoir which is the main reservoir in the Ghawar field. The Arab-D consists of a mixture of limestones and dolomites.