This field produces from a structure that lies above a deep-seated salt dome (salt has been penetrated at 9,000 ft) and has moderate fault density. A large north/south trending fault divides the field into east and west areas. There is hydraulic communication across the fault. Sands were deposited in aeolian, fluvial, and deltaic environments made up primarily of a meandering, distributary flood plain. Reservoirs are moderate to well sorted; grains are fine to very fine with some interbedded shales. There are 21 mapped producing zones separated by shales within the field but in pressure communication outside the productive limits of the field. The original oil column was 400 ft thick and had an associated gas cap one-third the size of the original oil column. Porosity averages 30%, and permeability varies from 10 to 1500 md.
Although conformance-improvement gel treatments have existed for a number of decades, their widespread use has only begun to emerge. Early oilfield gels tended to be stable and function well during testing and evaluation in the laboratory, but failed to be stable and to function downhole as intended because they lacked robust chemistries. Also, because of a lack of modern technology, many reservoir and flooding conformance problems were not understood, correctly depicted, or properly diagnosed. In addition, numerous individuals and organizations tended to make excessive claims about what early oilfield gel technologies could and would do. The success rate of these gel treatments was low and conducting such treatments was considered high risk. As a result, conformance-improvement gel technologies developed a somewhat bad reputation in the industry. Only recently has this reputation begun to improve. The information presented in this chapter can help petroleum engineers evaluate oilfield conformance gels and their field application on the basis of well-founded-scientific, sound-engineering, and field-performance merits.
The primary physical mechanisms that occur as a result of gas injection are (1) partial or complete maintenance of reservoir pressure, (2) displacement of oil by gas both horizontally and vertically, (3) vaporization of the liquid hydrocarbon components from the oil column and possibly from the gas cap if retrograde condensation has occurred or if the original gas cap contains a relict oil saturation, and (4) swelling of the oil if the oil at original reservoir conditions was very undersaturated with gas. Gas injection is particularly effective in high-relief reservoirs where the process is called "gravity drainage" because the vertical/gravity aspects increase the efficiency of the process and enhance recovery of updip oil residing above the uppermost oil-zone perforations. The decision to apply immiscible gas injection is based on a combination of technical and economic factors. Deferral of gas sales is a significant economic deterrent for many potential gas injection projects if an outlet for immediate gas sales is available. Nevertheless, a variety of opportunities still exist. First are those reservoirs with characteristics and conditions particularly conducive to gas/oil gravity drainage and where attendant high oil recoveries are possible. Second are those reservoirs where decreased depletion time resulting from lower reservoir oil viscosity and gas saturation in the vicinity of producing wells is more attractive economically than alternative recovery methods that have higher ultimate recovery potential but at higher costs. And third are reservoirs where recovery considerations are augmented by gas storage considerations and hence gas sales may be delayed for several years. Nonhydrocarbon gases such as CO2 and nitrogen can and have been used. In general, calculation techniques developed for hydrocarbon-gas injection and displacement can be used for the design and application of nonhydrocarbon, immiscible gas projects. Valuing the use of such gases must include any additional costs related to these gases, such as corrosion control, separating the nonhydrocarbon components to meet gas marketing specifications, and using the produced gas as fuel in field operations. The conceptual aspects of the displacement of oil by gas in reservoir rocks are discussed in this section. There are three aspects to this displacement: gas and oil viscosities, gas/oil capillary pressure (Pc) and relative permeability (kr) data, and the compositional interaction, or component mass transfer, between the oil and gas phases.
The Empire Abo field, located in New Mexico, US, covers 11,000 acres (12.5 miles long by 1.5 miles wide) and contains approximately 380 million stock tank barrels (STB) of original oil in place (OOIP). This reservoir is a dolomitized reef structure (Figure 1) with a dip angle of 10 to 20 from the crest toward the fore reef. The oil column is approximately 900 ft thick, but the average net pay is only 151 ft thick. The pore system of this reservoir is a network of vugs, fractures, and fissures because the primary pore system has been so altered by dolomitization; the average log-calculated porosity was 6.4% BV. Numerical simulations of field performance and routine core analysis data have indicated that the horizontal and vertical permeabilities are about equal.
Hydrocarbon production potential is often limited by constraints, and it is important that these constraints are understood and correctly represented when generating a realistic set of production profiles. The focus of this section is physical constraints in the system through which the fluid flows, but constraints applied because of reservoir management, contractual terms and economics are also highlighted. A production system includes the reservoir, wells, facilities and export system. Constraints within the system can be associated with any of the produced fluids (oil, gas or water) or a specific combination of them. For example, important factors to consider beyond the base deliverability of the reservoir are potential near-wellbore formation damage (skin), well tubing constraints, artificial lift availability, shared gathering system back pressures, flow line erosion velocity limits and facility capacities.
Activity scheduling is an important, integral part of production forecasting that can have a significant impact on the reliability of the forecast. Once the subsurface input has been established and agreed upon by multiple disciplines, the production forecast should be created taking into account system constraints, scheduled and unscheduled downtime and new activities such as well and field optimization, changes to facilities capacity or design and new wells and developments coming on production. Future development programs are a major component of activity scheduling. The timeline and production impact of the drilling program is estimated and layered onto the existing baseline forecast (commonly known as the "no further activity forecast"). This is typically done using type curves or a simulation model because the wells are not yet on production.
The production forecast should be consistent with the current reservoir drainage strategy and should include production from existing and new wells, side-tracks and well interventions. Short-term forecasts are most dependent on activity levels (number and timing of new wells and well interventions), while long-term forecasts are more affected by reservoir type and the above-mentioned subsurface assumptions. The above reservoir description should be based on all available field data, the quantity and quality of which will vary considerably from asset to asset depending on field location, maturity and the level of appraisal and surveillance. Key data includes 2D/3D seismic, well logs, PVT analysis, core analysis and well tests. Static and dynamic reservoir understanding, G&G and petrophysical interpretations, reservoir modelling and detailed analysis of both the reservoir and well performance are key factors in establishing the most optimal drainage strategy.
The following guidelines are provided to promote consistency in production forecasting and reporting. "Reporting" refers to the presentation of evaluation results within the business entity conducting the evaluation and should not be construed as replacing guidelines for subsequent public disclosures under guidelines established by regulatory and/or other government agencies, or any current or future associated accounting standards. Commercial terms refer both to those specified in Production Operating Agreements (POA) and to the tax laws existing in the affected countries. The POA typically describes the production entitlement of the operating groups and the mechanisms for sharing or recovering costs. The majority of this document focuses on forecasting the total production from a reservoir or field (gross volumes forecast).
Included are applications of foam for mobility control and for blocking gas. In 1989, Hirasaki reviewed early steam-foam-drive projects. In 1996, Patzek reviewed the performance of seven steam-foam pilots conducted in California. Early and delayed production responses were discussed for these pilots. Gauglitz et al. review a steam-foam trial conducted at the Midway-Sunset field of California.
Pathak, Varun (Computer Modelling Group Ltd.) | Hamedi, Yousef (Computer Modelling Group Ltd.) | Martinez, Oscar (Computer Modelling Group Ltd.) | Vermeulen, Stephen (Computer Modelling Group Ltd.) | Kumar, Anjani (Computer Modelling Group Ltd.)
Integrated production systems models are very valuable for predicting the performance of complex systems containing multiple reservoirs and networks. In addition, the value of quantifying uncertainty in reservoirs and production systems is immense as it can build confidence in operational investments. However, traditionally it has been extremely tedious to incorporate uncertainty assessments in the context of integrated production systems modelling. This has been addressed in the current work with the help of a case study.
In the current work, a complex integrated production systems model is presented - from Pre-Salt carbonates reservoir offshore of Brazil. The model includes multiple reservoirs with unique fluid types and complex fluid blending in the production network, multiphase and thermal effects in flowlines and risers, gas separation, gas processing, gas compression, and re-injection for either pressure maintenance or for miscible EOR.
The operational strategies, well placement, and well and network configurations are often based on a single geological realization. With the case study presented in this paper, an integrated way of quantifying geological uncertainty has been presented. A new multi-user, multi-disciplinary tool was used for this study that removed any discontinuities and inconsistencies that typically occur in such projects when multiple standalone tools are used for individual tasks. When quantifying uncertainty on production, the dependence on a single realization was eliminated as uncertain parameters were identified and used for creating robust probabilistic forecasts. Probability distribution curves were generated to represent the uncertainty in overall production from this asset, and the risk associated with operational investments was minimized.
Typically, an end-to-end uncertainty assessment is missing from the traditional Integrated Modelling workflows. With this new approach, the challenge of achieving a truly integrated uncertainty assessment for integrated reservoir and production models has been addressed successfully.