Relative Permeability Experiments Research Articles

Revisiting the Drainage Relative Permeability Measurement by Centrifuge Method Using a Forward–backward Modeling Scheme

Measurement of drainage relative permeability by the centrifuge method was first introduced by Hagoort (SPE J. 29(3):139–150, 1980). It has been shown that capillary end effects can cause error in the measurement of relative permeability if a minimum rotational speed is not honoured. To determine the minimum rotational speed that makes the capillary end effect negligible, ω min, we propose that the value of capillary-gravity number, N cg, should be of the order of 10−2 or smaller. This conclusion is based on the use a Forward–backward scheme consisting of a forward numerical simulator developed for centrifuge experiments and applying Hagoort’s method as a backward model. The article presents the use of this Forward–backward scheme as a powerful tool for error analysis such as determining the impact of capillary end effects. By using this loop, we first determine ω min for specific core and fluid properties. Later, we generalize the ω min calculations by using the definition of N cg as a “rule of thumb” for designing relative permeability experiments by centrifuge method. We also demonstrate another use of this loop for controlling the quality of the experimental data.

Experimental investigation of gas-water relative permeability for gas-hydrate-bearing sediments from the Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope

Permeability of hydrate reservoirs found in nature is likely to be heavily influenced by the percent of the pore volume occupied by hydrates. The quantification of how hydrate saturation affects permeability is of key interest for reservoir engineering studies. In this study, an experimental setup was modified to test permeability characteristics of unconsolidated core samples containing various saturations of methane hydrates. Hydrates were formed in the unconsolidated samples using a refrigerated core holder connected to a brine and methane injection system. Studies of this type conducted to date have rarely been performed on core samples recovered from actual hydrate-bearing sedimentary sections from natural hydrate intervals. Samples from the Mount Elbert site on the Alaska North Slope (ANS) were used for this study. Relative permeability measurements using hydrate constituent components (e.g. water and methane) are not very desirable due to difficulties in preventing additional hydrate formation during displacement experiments. Relative permeability measurements performed with hydrate constituent components (e.g. water and nitrogen) can help to significantly mitigate issues with additional hydrate formation. However, unsteady state relative permeability experiments produce piston like displacement results suggesting that steady state experiments might be preferable. It was observed that as in previous work using consolidated core samples, permeability of both brine and gases was reduced in unconsolidated hydrate-bearing core samples. Experimental results show that low to moderate hydrate saturations (1.5 to 36%) can significantly reduce permeability of porous media. These saturations, in fact, are lower than hydrate saturations observed in the natural hydrate systems at Mount Elbert.

Analysis of CO2 Endpoint Relative Permeability and Injectivity by Change in Pressure, Temperature, and Phase in Saline Aquifer

Carbon dioxide capture and geological storage are considered to be imperative practical means for reducing greenhouse gas emissions into the atmosphere. Among geological formations for carbon dioxide capture and geological storage, deep saline aquifer is tracked as a key site due to its huge potential and common occurrence when compared to oil and gas reservoirs. But, the two-phase behavior of CO2 accompanied with water formation under conditions equivalent to geological storage are mostly unknown. In this study, relative permeability experiments have been conducted to measure the end-point relative permeability of CO2 and investigations have been carried out to calculate injectivity using the relative permeability. In CO2 and water system, the injectivity is the function of the CO2 endpoint relative permeability. An experimental apparatus for CO2-water relative permeability was designed and experiments were carried out under six different temperatures varying from 70°F to 120°F, while the cell pressure was varied from 500 to 1,300 psi for every respective temperature. From the results, it was evident that, in general, the endpoint relative permeability of carbon dioxide increases with decrease in viscosity ratio, while the endpoint relative permeability in the transition region between gas and supercritical decreases even with decreasing viscosity ratio. Also, based on the sensitivity studies carried out by varying pressure and temperature, it was experimentally confirmed that porous and permeable aquifers at a minimum depth of more than 800 m are the most appropriate storage sites.

Artificial-Intelligence Technology Predicts Relative Permeability of Giant Carbonate Reservoirs

Summary Determination of relative permeability data is required for almost all calculations of fluid flow in petroleum reservoirs. Water/oil relative permeability data play important roles in characterizing the simultaneous two-phase flow in porous rocks and in predicting the performance of immiscible displacement processes in oil reservoirs. They are used, among other applications, for determining fluid distributions and residual saturations, predicting future reservoir performance, and estimating ultimate recovery. Undoubtedly, these data are considered probably the most valuable information required in reservoir-simulation studies. Estimates of relative permeability are generally obtained from laboratory experiments with reservoir-core samples. In the absence of the laboratory measurement of relative permeability data, developing empirical correlations for obtaining accurate estimates of relative permeability data showed limited success, and it proved difficult, especially for carbonate reservoir rocks. Artificial-neural-network (ANN) technology has proved successful and useful in solving complex structured and nonlinear problems. This paper presents a new modeling technology to predict accurately water/oil relative permeability using ANNs. The ANN models of relative permeability were developed using experimental data from waterflood-core-tests samples collected from carbonate reservoirs of giant Saudi Arabian oil fields. Three groups of data sets were used for training, verification, and testing the ANN models. Analysis of results of the testing data set shows excellent agreement with the experimental relative permeability data. In addition, error analyses show that the ANN models developed in this study outperform all published correlations. The benefits of this work include meeting the increased demand for conducting special core analysis (SCA), optimizing the number of laboratory measurements, integrating into reservoirsimulation and reservoir-management studies, and providing significant cost savings on extensive laboratory work and substantial required time.

Relative permeability as a function of temperature, initial water saturation and flooding fluid compositions for modified oil-wet chalk

This paper addresses the effect of brines, containing sulphate and magnesium (found in sea water) and distilled water as initial saturating and flooding fluids, on relative permeability of modified chalk cores by fatty acids to more oil-wet. A model oil system (n-decane) containing different fatty acids (present in oil) such as 18-phenyloctadecanoic acid (PODA—long chain fatty acid with unsaturated ring), Stearic acid (SA—saturated straight long chain), and brines containing sulphate and magnesium ions (0.03 M SO 4 2− and 0.06 M Mg 2+) dissolved in distilled water are used. Fatty acids alter the wettability of chalk to more oil-wet. PODA shows higher tendency compared to SA, at the same concentration, to alter the chalk to more oil-wet. Relative permeability curves are used as indication of the modified chalk behaviour. It also addressed the effect of the temperature on the relative permeability. A shift in the relative permeability to the right side indicates more water-wet with temperature up to ≤ 80 °C. At a higher temperature of 130 °C, the relative permeability curves indicate more oil-wet tendency. Wettability indicated by the relative permeability curves shows the influence of initially saturated fluid composition and the flooding fluid composition, where the modified cores initially saturated with ion free water (distilled water) and flooded by fluids containing Mg 2+ or SO 4 2− shows a shift indicating more water-wet compared to reference core (initially saturated and flooded by ion free water). However, if the initial saturating and flooding fluids contain 0.06 M Mg 2+ ions, the wettability tends to be more oil-wet compared to that if the modified cores are saturated and flooded with 0.03 M SO 4 2− and distilled water. The calculated pore size distribution index ( λ) using Huang and Honarpour correlation, is used to determine the corrected (actual) relative permeability for capillary end effect. A good agreement between experimental and simulated relative permeability data was also obtained by using the calculated λ.

Effect of Temperature, Wettability and Relative Permeability on Oil Recovery from Oil-wet Chalk

It is customary, for convenience, to use relative permeability data produced at room temperature. This paper shows that this practice underestimates oil recovery rates and ultimate recovery from chalk rocks for high temperature reservoirs. Above a certain temperature (80°C in this work) a reduction of oil recovery was observed. The reduction in oil recovery is reflected by the shift of relative permeability data towards more oil-wet at high temperature (tested here 130°C). However, both IFT and contact angle measurements indicate an increase in water wetness as temperature increases, which contradict the results obtained by relative permeability experiments. This phenomenon may be explained based on the total interaction potential, which basically consists of van der Waals attractive and short-range Born repulsive and double layer electrostatic forces. The fluid/rock interactions is shown to be dominated by the repulsive forces above 80°C, hence increase fine detachment enhancing oil trapping. In other words the indicated oil wetness by relative permeability is misleading.

Temperature effects on the heavy oil/water relative permeabilities of carbonate rocks

In this study, unsteady-state relative permeability experiments were carried out using unpreserved limestone and dolomite core samples obtained from the oil zones of heavy oil carbonate reservoirs. Experiments were conducted at reservoir pressure and original fluid saturations for a temperature range of 100–500 °F. The oil/water relative permeabilities in various temperatures were determined using the JBN method and history matching of the experimental data using numerical simulations. The applicability and limitations of the JBN techniques are discussed. The results suggest that relative permeabilities of oil and water in heavy oil carbonate systems are functions of temperature. Specifically, the shape of oil relative permeability changes with increasing temperature which might be caused by wettability alterations due to elevated temperature. This, in fact, disagrees with some previous studies dealing with sandstone systems. It was found that the residual oil saturation decreases and irreducible water saturation increases with increasing temperature.

Barrier properties of nylon 6-montmorillonite nanocomposite membranes prepared by melt blending: Influence of the clay content and dispersion state: Consequences on modelling

Polyamide 6-montmorillonites membranes have been prepared and studied for a large range of clay content (from 0 to 18 wt.%). The barrier properties of these systems have been determined for different diffusing molecules varying by their kinetic diameter and their interaction capacity. The relative permeability has been found to be independent on the diffusing molecule showing that a tortuosity effect is at the origin of the improved barrier properties. The crystalline morphology of the polyamide matrix has been shown to be only slightly dependent on the nanocomposite composition. Consequently, the permeation properties have been related to the clay content and dispersion. From a quantitative description of the montmorillonite particle dispersion, the ability of different geometrical models to describe the experimental relative permeability data is discussed. This modelling leads to the conclusion that it is necessary to consider the polydispersity of the impermeable filler shapes and to take into account the presence of surfactant located at the inorganic surface to appropriately model the transport properties of the nanocomposites in a large range of nanoclay contents.

Estimation of Flow Functions During Drainage Using Genetic Algorithm

Summary Unsteady-state relative permeability experiments followed by automatichistory matching have been used in the past for estimating relativepermeability and capillary pressure simultaneously. The performance of theautomatic history matching largely depends on the simulator, the functionalform of the flow functions, and the optimization tool. The Newton method iscommonly used as the optimization tool for the automatic history matching; wehave used a genetic algorithm (GA) as the optimization tool in this work. Oneof the advantages of GA is that it requires only function evaluations for thesolution searching and not Jacobian or gradient calculations as required by the Newton method. The Corey model and piece-wise spline interpolation were used torepresent the relative permeability. A new coding method in GA was developedfor piece-wise spline interpolation. In-situ saturation data were collectedduring an unsteady-state primary drainage experiment by CT scanning. Simulationand experimental data were used to test the performance of the algorithm. Testresults showed a good match between the simulation data and experimental datafor low-injection-rate primary drainage. At higher rates, GA did not convergeto the global optimum.

Limitations of Three-Phase Buckley-Leverett Theory

The broad objective of this study is to determine the limitations of the three-phase relative permeability estimation technique by using the experimental approach. In order to achieve this goal, three-phase relative permeability experiments were conducted on a Berea sandstone core plug by using brine, hexane and nitrogen gas. An unsteady-state analytical technique and a numerical technique where a black oil simulator was coupled with a global optimization algorithm in a least squares manner was used to compute three-phase relative permeabilities. It has been found that basic assumptions of linear flow and monotonic saturation changes, required for three-phase extensions of two-phase Johnson-Bossler-Nauman (JBN) theory, are violated in the displacement experiments, leading to errors in computed relative permeabilites even at high rates.

Prediction of Wettability Variation Within an Oil/Water Transition Zone and Its Impact on Production

We use a pore-scale network model in conjunction with conventional reservoir-scale simulations to investigate wettability variation within an oil/water transition zone. If the initial water saturation within the transition zone is controlled by primary drainage, we predict that initial production behavior is the same regardless of wettability. However, if the initial water saturation has been modified by movement of the free water level (FWL) following reservoir filling, then both the initial water saturation and production behavior are different depending upon wettability. In this case, the wettability of the reservoir may be estimated using in-situ measurements. Moreover, wettability variation may yield anomalous dry oil production from the transition zone. Over longer production timescales, wettability variation can result in high displacement efficiency during waterflooding. Assuming that the reservoir is uniformly water-wet or oil-wet, or using empirical hysteresis models, leads to a significant underestimate of recovery.

Development and Testing of Two-Phase Relative Permeability Predictors Using Artificial Neural Networks

Summary In this paper, we report liquid/liquid and liquid/gas two-phase relative permeability predictors that are developed using artificial neural networks (ANNs). In the development stage, some of the relative permeability data from literature are used during the training stage while some other sets are preserved to test the prediction capabilities of the models. Various rock and fluid properties, including endpoint saturations, porosity, permeability, viscosity and interfacial tension, and some functional links (mathematical groups coupling various rock and fluid properties) constitute the input parameters of the models. The models are found to successfully predict the field and experimental relative permeability data.

Combination of small angle scattering and three-dimensional stochastic reconstruction for the study of adsorption–desorption processes in Vycor porous glass

We study sorption and transport processes in dry and wet (preadsorbed with CH2Br2) Vycor glass by combining small angle scattering and three-dimensional (3D) stochastic reconstruction methods. Three-phase systems of solid, condensate, and void space, are generated for the first time, by the combination of the above methods. The resulting 3D images can visualize the evolution of the adsorption process and show how sorption alters the pore space characteristics of the material. Desorption is modeled in this system with the additional employment of an invasion percolation algorithm to account for the hysteresis effect caused by the inaccessible regions of the porous matrix. It is found that desorption is simulated very well provided that the main mechanism for hysteresis depends only on the topology of the pore space and not on thermodynamic effects. Based on a random-walk procedure, Knudsen transport properties of the reconstructed images are also determined for different degrees of saturation, providing very good agreement with experimental relative permeability data. Thus, relative permeability reflects purely the pore accessibility properties of the material and may assist in discerning their exact contribution to the equilibrium sorption hysteresis loop.

Three-phase flow and wetability effects in triangular capillaries

We performed a series of two and three-phase flow experiments in capillary tubes with equilateral triangular cross-sections. We measured the flow rates of oil and water in water-wet tubes and compared them with predictions using an empirical theoretical expression for fluid conductance. Our results are consistent with a free boundary condition at the gas/liquid interface, and with a no-flow boundary at the oil/water interface, when water is stationary, and a condition between a no-flow and a free-boundary when oil and water flow simultaneously. By studying oils with different spreading coefficients we measured the circumstances when oil layers form, and we compared the results with a simple geometric argument for oil layer existence. We also studied flow in uniformly oil-wet tubes. Overall, the work verifies and calibrates theoretical expressions for fluid conductance and layer formation that can be inputted into pore level network models to predict macroscopic properties, such as relative permeability. We illustrated this approach by using our work to interpret three-phase relative permeability experiments on sandpacks.

Adsorption–desorption gas relative permeability through mesoporous media—network modelling and percolation theory

Gas relative permeability in mesoporous media is investigated during both adsorption and desorption of a condensable vapour which causes pore blocking in the structure of the porous network. Three-dimensional regular lattices of various pore connectivities are considered and compared to effective medium (EMA) models and Bethe trees of infinite size. During adsorption, the corresponding relative permeability curves exhibit a nearly quadratic behaviour with the volume of adsorbate, in full agreement with percolation theory, while EMA predicts a linear relation between these properties. Bethe trees give a very good approximation of the relative permeability curve of three-dimensional regular networks, provided that the connectivity of the Bethe tree is properly adjusted so that the same percolation threshold is obtained with corresponding regular network. During desorption, relative permeability is only a function of accessible pores. However, the trapped supercritical pores contribute to vapour occupancy during adsorption and not during desorption resulting in hysteresis loops in the corresponding volume of adsorbate. In the case of gas relative permeability experiments using different sets of mesoporous materials and adsorbates, when reduced relative permeability curves are considered in the vicinity of the percolation threshold, they all exhibit a universal behaviour regardless the topology of the porous medium and the nature of the adsorbate.

Measurement and Correlation of Gas Condensate Relative Permeability by the Steady-State Method

SummaryHigh-pressure core flood experiments using gas condensate fluids in long sandstone cores have been conducted. Steady-state relative permeability points were measured over a wide range of condensate-to-gas ratios (CGR; volume of condensate per unit volume of gas, both at test pressure and temperature), and the velocity and interfacial tension (IFT) were varied between tests to observe the effect on relative permeability. The experimental procedures ensured that the fluid distribution in the cores was representative of gas condensate reservoirs. Hysteresis between drainage and imbibition during the steady-state measurements also was investigated, as was the repeatability of the data.A relative permeability rate effect for both gas and condensate phases was observed, with the relative permeability of both phases increasing with an increase in flow rate. The relative-permeability-rate effect was still evident as the IFT increased by an order of magnitude. The influence of end effects was shown to be negligible under the IFT conditions used in the tests, with the Reynolds number indicating that flow was well within the so-called laminar regime under all test conditions. The observed rate effect was contrary to that of conventional non-Darcy flow, where the effective permeability should decrease with increasing flow rate. A generalized correlation between relative permeability, velocity, and IFT has been proposed.The results highlight the need for appropriate experimental methods and relative permeability relations where the distribution of the phases are representative of those in gas condensate reservoirs.

Some practical applications of recent core analysis advances

The Eromanga Basin is Australia's main onshore oil province, consisting of a large number of thin good permeability reservoirs. This basin overlies the Cooper Basin, Australia's main onshore gas province, consisting of many thicker but low permeability gas reservoirs. Both basins often contain stacked reservoirs. In order to identify improvements in core analysis which can be applied to the basins the Operator has conducted a series of experiments using newly or recently developed procedures. Following are some highlights. (1) Reservoirs which may have leaked: Some Eromanga basin reservoirs are believed to have leaked into overlying reservoirs. For the reservoir which has leaked it is not really valid to compare the log analysis to a drainage capillary pressure curve. Neither does a traditional laboratory imbibition capillary curve exactly describe the process. A new laboratory imbibition procedure was developed which appears to match the log analysis better than drainage data. (2) Low invasion coring: This has become an established procedure in Australia. Many of our reservoirs are well suited to it. In one case we obtained saturations by four different laboratory procedures and compared them to the log analysis, obtaining a somewhat large spread in the various laboratory results. (3) Transitional reservoirs: For waterflood and some relative permeability experiments the traditional laboratory procedure of using high capillary pressure ( P c) to achieve s wc then a high flood velocity (or capillary number N) to achieve s or has been shown to produce incorrect results across the Eromanga Basin and has been replaced by a low P c/low N method, yielding better agreement with log analysis. (4) Mud testing on cores for formation damage: Comparison of a particle size distribution from the mud with a pore size distribution from the reservoir has a lot of pitfalls. It does not follow that particles much smaller than a pore automatically have the opportunity to enter the pore. (5) Spreading experiments: Two suites of experiments were conducted involving waterflooding a core followed by gasflooding it. One suite was run with a positive spreading coefficient, and the other with a negative spreading coefficient. Oil recovery was the same in both cases.

Measurement and Correlation of Gas Condensate Relative Permeability by the Steady-State Method

Abstract High pressure core flood experiments using gas condensate fluids in long sandstone cores have been conducted. Steady-state relative permeability points were measured over a wide range of condensate to gas ratio's (CGR), with the velocity and interfacial tension (IFT) being varied between tests in order to observe the effect on relative permeability. The experimental procedures ensured that the fluid distribution in the cores was representative of gas condensate reservoirs. Hysteresis between drainage and imbibition during the steady-state measurements was also investigated, as was the repeatability of the data. A relative permeability rate effect for both gas and condensate phases was observed, with the relative permeability of both phases increasing with an increase in flow rate. The relative permeability rate effect was still evident as the IFT increased by an order of magnitude, with the relative permeability of the gas phase reducing more than the condensate phase. The influence of end effects was shown to be negligible at the IFT conditions used in the tests, with the Reynolds number indicating that flow was well within the so called laminar regime at all test conditions. The observed rate effect was contrary to that of the conventional non-Darcy flow where the effective permeability should decrease with increasing flow rate. A generalised correlation between relative permeability, velocity and IFT has been proposed, which should be more appropriate for condensing fluids than the conventional correlation. The results highlight the need for appropriate experimental methods and relative permeability relations where the distribution of the phases are representative of those in gas condensate reservoirs. This study will be particularly applicable to the vicinity of producing wells, where the rate effect on gas relative permeability can significantly affect well productivity. The findings provide previously unreported data on relative permeability and recovery of gas condensate fluids at realistic conditions.

Gas Storage Reservoir Performance Optimization Through The Application Of Drainage And Imbibition Relative Permeability Data

Abstract Gas storage reservoirs are utilized in many locations to seasonally store gas in summer months for periods of high demand in the winter. This generally involves the cyclic pressurization and depressurization of the reservoir on an annual basis. If the storage reservoir overlies an aquifer or residual oil leg, this may involve the cyclic motion of the gas-liquid contact and gas zone. This paper documents an extensive series of reservoir condition relative permeability experiments conducted on core material from a gas storage reservoir in southern Ontario to investigate the effects of cyclical pressurization and depressurization on reservoir performance. The tests illustrate how the cycling of applied net overburden pressure and the presence of trapped gas and water saturations in the dynamic gas-liquid transition zone can affect the production and injection of gas in the storage reservoir. Applications of the data, and extensions to field performance are also presented. Introduction For many years, natural underground geologic traps have been utilized for storing gas and liquid hydrocarbons; these reservoirs are usually developed from known hydrocarbon reservoirs which have since been abandoned. The primary application of storage reservoirs is in the accumulation and storage of natural gas during periods of low demand in the summer months so that a large localized source of gas is readily available for periods of increased demand in the winter. For this reason, the reservoir is subjected to annual cyclic pressurization and depressurization as the gas is stored and removed from the reservoir. When an active aquifer or residual oil leg is present in the reservoir, these cyclic pressure fluctuations can result in an annual transgression and regression of the gas liquid contact. Encroachment of the liquid phase into the previously uninvaded portion of the reservoir is of interest to the operators of these fields because the residual saturation of the encroached fluid can have a profound effect on the deliverability and general performance of the contacted pore space. Experimentation and investigation of this phenomenon is possible through imbibition and drainage simulations to quantify the effects caused by two phase relative permeability relationships. An additional phenomenon associated with reservoir pressure cycling is that of rock compressibility effects. The gross overburden of the field remains constant as the internal pore pressure of the system oscillates. This yields a variation in the magnitude of the rock compressibility while the net overburden pressure changes as a function of pore pressure. The complexity of this scenario is further complicated by the compression and expansion of the trapped gas phase in the liquid filled pores. Hycal Energy Research Laboratories Ltd., in conjunction with Union Gas Limited, applied recent advancements in reservoir condition relative permeability techniques to conduct an extensive series of experiments to investigate the effects of these phenomena in the gas storage environment. Applications of the experimental data to field scenarios is also discussed.

The Eakring Dukeswood oil field: an unconventional technique to describe a field’s geology

The Eakring Dukeswood oil field of Nottinghamshire was last produced in 1971. All wells have since been abandoned and the licence ML 1 expired on 22 April 1992. Cumulative production was small by North Sea standards, but during the Battle of the Atlantic the field produced the bulk of the UK’s indigenous crude, peaking at 1600 BOPD in 1941. Cumulative recovery was some 6.5 MMSTB from an estimated 25.6 MMSTB in place in the completed horizons. In 1986 a study was undertaken to evaluate the remaining reserve potential. The primary tool for such work would normally be a detailed geological model, but since less than 25% of the 197 grid drilled wells have any wireline logs or cores only structural models existed. There is very little seismic. A further complication is that there were nine productive horizons and the majority of well completions were unsegregated over four of them. Only 20% of cumulative production can be assigned unequivocally to any one reservoir. Reservoir models, and individual reservoir contributions to production, had to be determined using less conventional techniques. Individual well performance under recycled peripheral water flood has proved to be a powerful tool to determine reservoir connectivity. Mapping decline rate reversal and water breakthrough by month indicates the transmissibility fairways and no-flow barriers in the system. It has also proved in some circumstances a useful discriminator of reservoir contribution. The reservoirs are mainly Westphalian A to Namurian B siliciclastics. All were undersaturated at initial conditions. Porosity is often secondary, rarely above 20% and absolute permeability ranges from less than 1 to several hundred mD. Irreducible water saturation (S wi ) from mercury injection data ranges between 30 and 50% and water flood experiments indicated residual oil saturation (S or ) at 30%. The oil is waxy, up to 16% by weight, and has a high viscosity with correspondingly unfavourable mobility. API gravities range from 31.9–37.6°. Most production was obtained from the Loxley Edge Rock, the Sub Alton and Crawshaw sandstones—all by depletion drive, and from the Ashover Grit—in part water driven. Post-war water flooding was directed mainly at the Sub Alton and Crawshaw units. Regional studies and sedimentological examination of two recent adjacent wells established the likely broad reservoir anatomy. This was then refined for the field from the qualitative transmissibility maps constructed from flood front behaviour. Geological models could then be assembled with some confidence and bypassed oil and secondary accumulations were identified. Relative permeability experiments on the modern core indicate an additional field reservoir/accumulation, previously unrecognized.