Solution Gas-Drive Reservoirs Research Articles

Natural Dumpflood in Malaysia Succeeds as Low-Cost Offshore Oil-Recovery Method

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 196498, “First Natural Dumpflood in Malaysia: A Successful Breakthrough for Maximizing Oil Recovery in an Offshore Environment With Low-Cost Secondary Recovery,” by Muhammad Abdulhadi, SPE, Toan Van Tran, SPE, and Najmi Mansor, Dialog Group, et al., prepared for the 2019 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 29–31 October. The paper has not been peer reviewed. The complete paper describes the first successful implementation of natural dumpflooding offshore Malaysia as a case study to provide insight into the value of using the approach to maximize oil recovery in a mature field, particularly in a low-margin business climate. Background Field B, located offshore Balingian province approximately 80 km northwest of Bintulu, has a water depth of 90 ft and is highly compartmentalized and faulted, with almost 100 faults present. The field features three subfields further divided into nine major fault compartments. Eight primary reservoirs exist, with more than 20 subreservoirs stacked atop one another with multiple drive mechanisms, including water drive, gas-cap drive, and solution gas drive. Several of these subreservoirs are thick sands between which communication exists through juxtapositions, shared gas caps, or aquifer. Other subreservoirs are isolated by thin layers of shale apparent in certain wells but absent in others. The high complexity of Field B requires any opportunity identified to be thoroughly evaluated and examined before execution. Field B is a moderately sized field discovered in 1976, with production commencing in 1984. During the 30 years of oil production, the field peaked at 30,000 B/D in 1990 and dipped to 3,000 B/D in late 1999. The facilities consist of four drilling platforms, a processing platform, and a compressor platform. A total of 48 wells were drilled in the field, with most wells completed as dual-string producers. The recovery factor (RF) of the reservoirs ranges from 10% for solution gas drive to 50% for strong water drive. The behaviors of these reservoirs are starkly different. The solution gas-drive reservoirs have poor-quality sand (less than 200 md), a low productivity index, limited sand thickness (less than 30 ft), limited sand connectivity, and sharp pressure decline after 2 to 3 years of production. The water-drive reservoirs, however, have good-quality sand (up to 5,000 md), a high productivity index, thick sand (greater than 40 ft), extensive sand connectivity, and limited pressure decline. The stark differences in the reservoirs’ behavior further complicate field management. The field currently is in late life, with recovery to date of 19% with an RF of 23%. Most of the water-drive reservoirs are already swept up to the crest, while the solution gas-drive reservoirs are depleted nearly to abandonment pressure. After 30 years of production, the total field water cut was at 80%, while oil production was approximately 5,000 B/D, signifying the diminishing economic life of the field.

Inflow Performance Relationship Correlation for Solution Gas-Drive Reservoirs Using Non-Parametric Regression Technique

Background:The Inflow Performance Relationship (IPR) describes the behavior of flow rate with flowing pressure, which is an important tool in understanding the well productivity. Different correlations to model this behavior can be classified into empirically-derived and analytically-derived correlations. The empirically-derived are those derived from field or simulation data. The analytically-derived are those derived from basic principle of mass balance that describes multiphase flow within the reservoir. The empirical correlations suffer from the limited ranges of data used in its generation and they are not function of reservoir rock and fluid data that vary per each reservoir. The analytical correlations suffer from the difficulty of obtaining their input data for its application.Objectives:In this work, the effects of wide range of rock and fluid properties on IPR for solution gas-drive reservoirs were studied using 3D radial single well simulation models to generate a general IPR correlation that functions of the highly sensitive rock and fluid data.Methodology:More than 500 combinations of rock and fluid properties were used to generate different IPRs. Non-linear regression was used to get one distinct parameter representing each IPR. Then a non-parametric regression was used to generate the general IPR correlation. The generated IPR correlation was tested on nine synthetic and three field cases.Results & Conclusion:The results showed the high application range of the proposed correlation compared to others that failed to predict the IPR. Moreover, the proposed correlation has an advantage that it is explicitly function of rock and fluid properties that vary per each reservoir.

Inflow Performance Relationships Under Gravity Segregation for Solution Gas-Drive Reservoirs

This paper analyzes the influence of gravity segregation effects on inflow performance relationship (IPR) curves, with both totally and partially penetrated vertical wells. Using synthetic responses from a finite difference simulator, the effects of different parameters, such as vertical to radial permeability ratio, production mode, position of productive interval, oil rate, and mechanical skin, on the shape of IPR curves are documented. It is shown that greater flow potentials are obtained when the ratio of gravity to viscous forces increases. It is shown that for the case of partially penetrated wells, the IPR curve generated at constant bottomhole pressure does not coincide with the IPR generated at constant oil rate. Also, the presence of gravity segregation affects the values of absolute open flow potential, obtaining big differences with the corresponding values when gravitational effects are ignored. The values of the exponent n of Fetkovich IPR and the coefficients of the quadratic equation proposed by Jones et al. are functions not only of time but also of production rate, position of productive interval, and other parameters. The consequence of the above results is that the interpretation of IPR curves is affected by the presence of gravitational effects and therefore the use of traditional methods, such as those of Vogel , Fetkovich, or Jones et al., is restricted to the specific conditions considered by these authors.

Three-Phase Relative Permeability Measurement Using a Nuclear Magnetic Resonance Technique for Estimating Fluid Saturation

Abstract A method is described for measuring two- and three-phase relative permeabilities in sandstones or sand packs using a nuclear magnetic resonance (NMR) technique to determine fluid saturations Two- and three-phase relative permeabilities have been determined on Boise sandstone using the NMR technique of saturation measurement. Three- phase relative permeability to water was found to depend only on the water saturation, whereas three-phase permeability to oil depended on both the water and oil saturations. Relative permeability to gas in three-phase flow was found to depend only on the total liquid saturation. Introduction Three-phase relative permeabilities are extremely useful in calculating field performance for reservoirs being produced by simultaneous water and gas drives. Three-phase relative permeability data are also needed for analyzing solution gas-drive reservoirs which are partially depleted and are being produced by water drive. Some thermal recovery processes involve three-phase flow which require three-phase relative permeability data for predicting reservoir-behavior. Unfortunately three-phase relative permeability measurements have rarely been made. Also, because of the scarcity of three-phase data, it has not been possible to date to relate other measured rock characteristics to the relative permeabilities with a great certainty. Leverett and Lewis, Reid and Snells have reported three-phase relative permeability data on unconsolidated sands. Leverett and Lewis used ring electrodes spaced along the length of the sand sample to -measure the resistivity of the sample which was assumed to be monotonically related to brine saturation. Gas saturation was determined from pressure-volume measurements. Oil saturation was obtained by material balance on the cell containing the sand sample. This method is involved and time consuming. Another difficulty arises from the fact that the resistivity of the sand is a function not only of saturation of brine but also of the distribution and saturation history of the brine in the pore spaces. Reid used a gamma ray absorption technique for measuring liquid saturation. This method has the disadvantage that total liquid saturation rather than oil or brine saturation is all that can be measured and still another method is required to determine the saturations of individual components. Snells used a neutron bombardment method which also required a separate determination of the individual component saturations. Caudle et al. measured three-phase relative permeability on consolidated sandstones using vacuum distillation for determining fluid saturations. Distillation after each reading makes this technique very lengthy and time consuming. Corey et al and Naar and Wygal measured three-phase relative permeability on sandstones by the capillary- pressure method. Semipermeable diaphragm assemblies were used at each end of the core specimen to keep the water base in the core. Gravimetric methods were used to determine fluid saturations. Sarem recently repeated an unsteady-state method for measuring three-phase relative permeability on sandstones. This method is an extension of Weige's methods for measuring two-phase relative permeability. Although Sarem's method is simple and comparatively fast, the assumptions involved may oversimplify the problem. Sarem's assumption, that in all rocks relative permeability to each fluid will depend only on the saturation of that fluid, seems to be rather unrealistic. Neglecting capillary effects at the end of the core is also a weak assumption Donaldson and Deans measured three-phase relative permeability using a method similar to Sarem's.

Estimation of Ultimate Recovery from Solution Gas-Drive Reservoirs

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 132–138. Introduction In the past few years several articles and papers presenting results of solution gas-drive depletion calculations have appeared in the literature. Such calculations are of interest to the oil industry, for investment decisions must often be made before much is known about a reservoir. At other times, an estimate of the possible benefits to be realized from alternate production methods is desirable, and theoretical depletion calculations can serve as a floor or reference level from which to work. In any case, an estimate of ultimate oil recovery based upon engineering data is commonly required. An engineer confronted with the problem of obtaining, for a specific reservoir system, an estimate of ultimate oil recovery by solution gas-drive depletion usually will be forced to perform the calculations himself. This is despite the quantity of data in the literature. Rarely will either experience or the literature provide results from a reservoir system similar in all important respects to the one under consideration, and calculated results are not so plentiful that satisfactory interpolation procedures can be devised. Performing the calculations, however, is a tedious, time-consuming task unless an electronic computer is available, and, in practice, time and manpower are not always available for this purpose. A quick, simple, consistent method was needed for reducing the uncertainty in estimated oil recovery from solution gas-drive reservoirs when only minimum information about the reservoir system is available. Procedure Method of Calculation The usual requisite assumptions were made so that the material balance equation could be used to calculate data for the charts. The following assumptions were made:the reservoir is homogeneous and isotropic;oil recovery is due entirely to solution gas drive and neither a gas cap nor a water drive nor gravity drainage is present;the initial reservoir pressure is the bubble-point pressure of the reservoir fluid;initial total liquid saturation is 100 per cent of pore space;interstitial water saturation remains at the initial value as the reservoir pressure declines from the bubble-point pressure to atmospheric pressure;equilibrium gas saturation is 5 per cent of pore space; andoil and gas saturations are uniformly distributed throughout the reservoir at all times. There are no saturation gradients due to a wellbore, nor is the geometry of the reservoir system considered.

Flooding of Semi-Depleted Solution Gas Reservoir in Fullerton Field

Abstract Little flooding experience or technology exist which are applicable to solution gas-drive reservoirs which have been depleted considerably below the bubble point. The Fullerton field pilot is an example of flooding under these conditions where an intermediate stage or depletion exists and the water flooding will be neither a pressure maintenance project nor a depletion flood. In the case of Fullerton field where the gas saturation is approximately 18.0 per cent of total pore volume, "fill-up" will not be reached for a number of years after flooding operations begin. During this period compressibility of fluids and relative permeability factors determine performance of producing wells. The non-steady-state performance which will be in effect for a considerable time cannot be directly predicted by any presently accepted theoretical means. The pilot flood has yielded considerable information which can be used in predicting performance during this important stage of flooding. The pilot has shown that favorable reactions on producing wells adjacent to injection wells are in effect long before a theoretical fill-up is obtained. This does not indicate poor performance, but merely that the reservoir fluids are compressed to the point where a significant oil bank is formed. This isolated pilot pattern flood, where all offset wells are producing, gives some indication of what might be expected under both pattern and line-drive flooding. The pilot has progressed to a point where sufficient stock-tank oil has been recovered, in the area under pattern flooding, to justify full scale flooding. In the area surrounding the pattern flood no means exist for confining fluid movement, and performance is a function of the interdependent combination of relative permeability, fluid saturation and fluid compressibility. This pilot flood has shown the degree to which outside offset producing wells respond prior to reaching gas-space fill-up and the degree to which productivity is affected by changes in saturation accompanied by only relatively slight pressure increase. Producing wells inside the pattern flood have shown the degree to which productivity can be affected by saturation change and a considerable increase in bottom-hole pressure.