Unfractured Reservoirs Research Articles

An improved response equation of dual laterolog in dual porosity reservoirs and its solution scheme and applications in fractured reservoirs

Many fractured reservoirs are dual porosity reservoirs including matrix pores and fractures, which both contribute to the porosity. However, previous studies either ignored the effect of pores or fractures on dual laterolog, or had special application conditions. Considering the joint contribution of pores and fractures, a response equation of dual laterolog in dual porosity reservoirs is established. First, based on a borehole model with a vertical fracture in dual porosity reservoirs, fracture porosity equations are established in the investigation depths of deep and shallow laterologs, respectively. Using Archie's equations, the response equations of deep and shallow laterolog resistivities are derived, respectively. Then, the response equation, which is similar to the traditional equation of dual laterolog in fractured tight reservoirs, is established. It contains three unknown parameters, i.e. fracture width, fracture cementation exponent and matrix cementation exponent. To solve the equation, a virtual core model is proposed to estimate the fracture cementation exponent by fracture width. The estimation method of matrix cementation exponents is established by empirical formulas. Then, the response equation can be transformed into a nonlinear equation with one unknown parameter of fracture width, and conventional iterative methods can be employed to solve it and obtain the fracture width. Using the response equation and the solution scheme, the change characteristics of fracture cementation exponents in different fractured reservoirs are first analyzed. It shows that the fracture cementation exponents increase with the fracture widths, and they decrease with the increase of the ratio of formation water resistivity to unfractured reservoir resistivity. The applications indicate that the equation and solution scheme can obtain relatively accurate fracture widths quickly in dual porosity reservoirs, and they are recommended for dual porosity reservoirs with high fracture angel (>70°) and low fracture density (<1/3.78 m-1). The findings of this study can help better understanding of the different contributions of fractures and pores to dual laterolog responses in dual porosity reservoirs, and they can provide an alternative solution for evaluating dual porosity reservoirs.

Production Calculation Model of Thermal Recovery after Hydraulic Fracturing and Packing in Tight Reservoir

It was deemed important to calculate the thermal recovery production model of tight oil reservoirs after fracturing and packing based on the field data of an oilfield in Bohai Sea, China. The thermal recovery production of a tight oil reservoir after fracturing is demonstrated through theoretical calculation and practical field data on the premise of five hypotheses. Fractures change the fluid flow capacity of the reservoir. Combined with the relevant theories of reservoir thermal production, the dual porosity system in the fractured zone and the single porosity system in the unfractured zone were established. The calculation models of heat loss in the fractured and unfractured zones were derived to determine the thermal recovery heating radius of the reservoir after fracturing and packing. Combined with the pseudo-steady state productivity formula of the composite reservoir, a production calculation model of thermal recovery after fracturing and packing in the tight oil reservoir was established. The results showed that the heating radius of the reservoir after fracturing and packing is smaller than that of the unfractured reservoir, and the additional heat absorption of the fracture system generated by fracturing and packing reduces the thermal recovery effect. The thermal recovery productivity of heavy oil reservoirs is mainly affected by the heating radius. With the increase of fracture density, the heating radius decreases and production decreases. The increase of fracture porosity also leads to the decrease of the heating radius and the production. The calculation result of this model is improved after tight oil reservoir fracturing during the production period, which indicates that the model has a better prediction effect of the production of the tight reservoir after fracturing and packing.

Assessment of the high-temperature aquifer thermal energy storage (HT-ATES) potential in naturally fractured geothermal reservoirs with a stochastic discrete fracture network model

High-temperature aquifer thermal energy storage (HT-ATES) is a cost-effective and suitable technology to store large amounts of energy. HT-ATES has been demonstrated to be an efficient and stable tool to buffer seasonal imbalances and significantly reduce greenhouse gas emissions. Fractured reservoirs are widespread in sedimentary basins worldwide. However, naturally fractured reservoirs have received little attention as potential formations for HT-ATES. The main concern regarding thermal energy storage in naturally fractured formations is the high fracture permeability, which may result in fast fluid flow and an increase in thermal losses. Therefore, quantification of the effects of fracture flow is essential to HT-ATES site verification.An HT-ATES system in a generic fractured reservoir is simulated with a 3D stochastically generated discrete fracture network (DFN) model combined with a fluid flow and heat transport model. The pressure and temperature evolutions at the well are analyzed, and the total extracted energy and thermal recovery efficiency are evaluated. The results confirm that the presence of the DFNs enhances thermal loss and thereby results in a lower thermal recovery efficiency compared with those of an unfractured reservoir. Such a decrease can reach 20%. However, simulations show that naturally fractured reservoirs might be potential candidates for HT-ATES due to a larger injectivity. A further discussion is conducted to characterize the relative importance of the hydrogeological properties of the fractures and fracture network structure on the thermal behavior of the HT-ATES system.This study provides preliminary insights into the impacts of complex natural DFN on the thermal performance of HT-ATES in fractured reservoirs.

Effect of fracture characteristics on history matching in the Qamchuqa reservoir: a case study from Iraq

Carbonate reservoirs in the Middle East hold a significant proportion of the remaining conventional oil reserves, which most of them were classified as naturally fractured. These reservoirs are well known for their low recoveries compared with their counterpart clastic unfractured reservoirs. Therefore, boosting their recoveries can assure to sustain the energy supply to the global oil markets. In this work, an example from the Middle East has been used to evaluate the impact of the fracture characteristics on the reservoir performance using four decades of production history. The characteristics of natural fractures have a remarkable impact on fluid flow behaviour in fractured reservoirs. Besides, these characteristics, such as fracture intensity, determines the matrix block dimensions, which in turn, influence the matrix recovery. However, it is challenging to estimate the fracture characteristics accurately due to the scarcity of the fracture data from subsurface measurements. Therefore, outcrop analogue data can be utilised to enhance the fracture modelling in fractured reservoirs and to fill the data gap between the seismic scale and well scale. In this work, we have integrated the outcrop fracture data with the core observations to improve the fracture modelling in the studied reservoir. Furthermore, a sensitivity study was carried out to investigate the impact of flow curves, gravity drainage mechanism, and its parameters, as well as the fracture storativity on the history matching in fractured reservoirs. Excellent matching results were obtained for the majority of the wells, as indicated by the low mismatch values. The obtained results highlighted the importance of fractures on the fluid flow behaviour, and hence the reservoir performance. Therefore, fracture properties should not be abusively modified using multipliers and local adjustment to avoid nullifying the reservoir characterisation efforts and degrade the simulation model capability for a future prediction.

Porosity evolution of two Upper Carboniferous tight-gas-fluvial sandstone reservoirs: Impact of fractures and total cement volumes on reservoir quality

Abstract Cyclic fluvial, coal-bearing sandstones from the Upper Carboniferous are important tight-gas reservoirs in the Lower Saxony Basin, NW Germany. Two wells from two fields located 10 km apart, both comprising of Westphalian C/D fluvial sandstones were studied. Well A was affected by approximately 1.2 km and well B of approximately 2.8 km of basin inversion after maximum burial depths larger than 5 km. Both fields display significant differences in recovered resources. An integrated core study combining sedimentological, petrographic and petrophysical data illustrates the impact of different diagenetic pathways. While permeability values appear in the same range of 0.01–1 mD for both fields, lithologies from well A of field A have average matrix porosities of 6% in a generally unfractured reservoir, whereas lithologies from well B of field B have matrix porosities of 10% in an overall fractured reservoir. Intense siderite/ankerite cementation in matrix and fractures is present in sandstones from both fields and can be related to fluid migration during basin inversion. In contrast, the strong alpine tectonic inversion affecting field B results in a lower thermal exposure since the late Cretaceous, resulting in smaller quartz cement volumes than in field A and larger matrix porosities in field B. Thus, matrix porosity is overall better due to smaller total cement volumes in field B. The study indicates a strong impact of fractures on tight sandstone reservoir quality and quartz cementation on hydrocarbon production performance from the sandstone matrix. Observations may be applicable to similar, strongly inverted tight gas sandstone fields and may directly affect exploration strategies.

Screening improved recovery methods in tight-oil formations by injecting and producing through fractures

Tight-oil reservoirs exhibit two characteristic behaviors that limit potential for improved recovery: (i) limited fluid movement from the unfractured matrix limits the potential to sweep additional oil towards the production wells with injection of a displacing fluid, (ii) the wettability of these reservoirs tend to be oil-wet which holds oil in relatively smaller pores, as compared to gas or water, making it difficult to mobilize that trapped oil. Primary oil production from these formations can decline to half of initial rates in the first year due to low permeability in the unfractured reservoir matrix, and a large amount of unrecovered oil remains in smaller pores that is not able to move out. To address these challenges, this study investigates the potential to improve oil recovery from tight-oil reservoirs by a method that includes injecting a fluid into the fractured reservoir to produce hydrocarbons from adjacent fractures intersecting the same wellbore. The injection and production through fractures has a potential economic advantage over huff-n-puff scheme such that there is no lag-period between injection and production. We compare the estimates of incremental oil recovery obtained by injecting water, immiscible CO2, and surfactant over the oil recovered by primary depletion (with no injection). The results suggest that injection of fluids may not always improve recovery from tight-oil reservoirs, especially in a heterogeneous reservoir (having different rock types) whose average matrix permeability is lower than 0.01mD. In cases where recovery is improved over primary depletion, water flood and surfactant flood perform almost equally well with no noticeable difference between the two. Although, surfactant results in favorable fluid properties to mobilize oil, the reason surfactant did not perform well in tight-oil formation studied here is because the unswept oil is inaccessible due to small permeability, and not because of high capillary pressure.

Multiscale Simulation of WAG Flooding in Naturally Fractured Reservoirs

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 164837, ’Multiscale Simulation of WAG Flooding in Naturally Fractured Reservoirs,’ by Mohamed Ahmed Elfeel, Adnan Al-Dhahli, Sebastian Geiger, SPE, and Marinus I.J. van Dijke, Heriot-Watt University, prepared for the 2013 EAGE Annual Conference and Exhibition/SPE Europec, London, 10-13 June. The paper has not been peer reviewed. Naturally fractured reservoirs (NFRs) contain a significant amount of remaining petroleum reserves and are now being considered for water-alternating-gas (WAG) flooding as secondary or tertiary recovery. The authors face the challenge of reservoir simulation of WAG by building models at various scales, starting with pore scale and expanding to an intermediate scale and then to reservoir scale. They show how pore-network modeling and fine-grid modeling where the fractures and matrix are represented explicitly can be used to increase the accuracy of numerical simulations at field scale. Introduction A significant portion of the world’s remaining petroleum resources is located in NFRs, including supergiant fields in the Middle East. A detailed understanding of the recovery processes involved in extracting hydrocarbons from NFRs by use of enhanced-oil-recovery techniques is key to increasing ultimate recovery for such reservoirs. Waterflooding has been used with various degrees of success in NFRs. For unfavorable (i.e., mixed- to oil-wet) matrix wettability, however, waterflooding can be ineffective. Gas/oil gravity drainage (GOGD) provides an important drive mechanism that can be effective irrespective of the rock wettability. In NFRs, fractures increase the exposure of the injected gas to oil in reservoir rock, which renders GOGD more effective than it is in unfractured reservoirs. Consequently, gas injection has been applied in many NFRs. However, because the gas mobility is very high compared with that of water and oil, so is the risk of bypassed oil and gravity override, which can lead to very early gas breakthrough. This is particularly true for NFRs. WAG flooding combines the merits of the two injection fluids on macroscopic and microscopic scales while stabilizing the injection front, delaying breakthroughs, and, therefore, leading to increased oil recovery compared with continuous water or gas injection. Reservoir simulation of WAG injection is very challenging because a representative three-phase saturation model is required to predict relative permeability and capillary pressure as water and gas saturations increase and decrease alternately. Three-phase relative permeability and capillary pressure data are extremely difficult to measure experimentally. Even if experimental evaluation becomes feasible, an infinite number of saturation paths can occur in the reservoir. This necessitates the use of empirical, or interpolation, models to predict three-phase relative permeability and capillary pressure from two-phase experiments. In NFRs, capillary pressure and relative permeability functions have a major effect on fluid exchange between matrix blocks and fractures. Predicting the effects of the interplay of viscous, capillary, and gravity forces is challenging because fluid flow is viscous-dominated in the fractures while transfer between fractures and matrix blocks is dominated by capillary and gravity forces. Because most of the oil is contained inside the matrix, capillary and gravity forces can be more important in NFRs than in conventional reservoirs.

Numerical Modeling of Diffusion in Fractured Media for Gas-Injection and -Recycling Schemes

Summary Diffusion in fractured reservoirs, unlike in unfractured reservoirs, can affect significantly the efficiency of gas injection in oil reservoirs and recycling in gas/condensate reservoirs. The physical diffusion, similar to gravity, results in the change of the path of the injected gas species from the fractures to the matrix, giving rise to late breakthrough. In this work, we present, for the first time, a consistent model to incorporate physical diffusion of multicomponent mixtures for gas-injection schemes in fractured reservoirs. The multicomponent diffusion flux is related to multicomponent diffusion coefficients, which are dependent on temperature, pressure, and composition. These coefficients are calculated from a model based on irreversible thermodynamics. Current simulation models of fractured reservoirs that include diffusion are based on inconsistent models of gas-to-liquid diffusion at the fracture/matrix interface. We avoid this deficiency by assuming that the gas and liquid phases are in equilibrium at the interface. The concept of crossflow equilibrium (i.e., vertical equilibrium) is invoked in our model to avoid the use of transfer functions. In this work, we use the combined discontinuous Galerkin and mixed methods on 2D structured grids to calculate fluxes accurately and to have low numerical dispersion to study physical diffusion. Four examples are presented. In one of the examples, a field-scale study is performed to investigate gas injection in a fractured reservoir away from miscibility pressure and close to miscibility pressure. Results show a significant effect of diffusion on recovery performance away from miscibility pressure. In another example, recycling in a fractured gas/condensate reservoir is presented to demonstrate that diffusion has a significant effect on condensate recovery.

Influences of Different Modes of Reservoir Heterogeneity on Performance and Oil Recovery of Carbon Dioxide Miscible Flooding

Abstract Reservoir heterogeneity represents one of the most dominant factors affecting the performance of CO2 miscible flooding and its expected oil recovery. The main goal of this study is to investigate the influence of different modes of reservoir heterogeneity on oil recovery by supercritical CO2 miscible flooding. The investigated heterogeneity modes include:different single fractured reservoirs of different inclination angles,different permeability configurations of layered reservoirs, andthe sequence of permeability distributions in composite reservoirs. Complete reservoir rock and oil compositional analyses were performed. The minimum miscibility pressure (MMP) of oil-CO2 was mathematically calculated using several empirical correlations and determined experimentally using slim tube tests. The core flood tests were achieved using actual fluids injected through 12 actual reservoir rock samples. Of these, four samples were of different fracturing angles as single fractured reservoirs, four samples were of different permeability configurations as layered rocks and four samples represented composite reservoirs. The slug size of supercritical CO2 was optimized to be 0.15 PV, injected and chased by actual reservoir brine through these different simulated modes of reservoir heterogeneity. The results indicated that all different modes of reservoir rock heterogeneity have a crucial influence on oil recovery by CO2 miscible flooding in carbonate oil reservoirs. Of note, unfractured reservoirs produced higher oil recovery by CO2 miscible flooding than single fractured ones. An oil reservoir with a 30 degree inclination angle of single fracture produced the highest oil recovery, whereas, fractured rocks with a 45 degree fracture produced the minimum oil recovery in this category. The rock permeability sequences of medium-low-high (MLH) mode for composite reservoirs and medium-high-low (MHL) distribution mode for layered reservoirs are highly recommended for CO2 miscible flooding. The results have proven the suitability of the CO2 application for layered and composite heterogeneous carbonate reservoirs, however, it does not recommend this EOR process for single fractured reservoirs. The results have also shown a real impact on oil recovery of the reservoir heterogeneity mode prevailing in the reservoir under development by this EOR process. Introduction The major applications of active carbon dioxide flooding projects were found in the U.S. Permian Basin, located in West Texas and Eastern New Mexico. Other projects were also active in Colorado, Louisiana, Mississippi, Oklahoma, Utah, Wyoming, and in Canada, Turkey (Bati Raman), Trinidad and Hungary (Budafa). The number of CO2 projects have increased in the U.S. and worldwide over the last number of years(1–3). Reservoir characterization has been considered one of the most important components of reservoir development because it provides a better description and distinguishes essential features of reservoir heterogeneities affecting fluid flow in pay formations. It has been proven that a better reservoir description and/or characterization reduces the amount of oil left in oil reservoirs. The main purpose of reservoir characterization is to outline and specifically integrate different forms of heterogeneities of the reservoir oil. Forgotson(4) defined reservoir characterization as the quantitative description of the physical and chemical properties of the porous medium and its contained fluids.

Seismic anisotropy in sedimentary rocks, part 2: Laboratory data

Part one of this paper presents a method for measuring seismic velocities and transverse isotropy in rocks using a single core plug. This method saves at least two‐thirds of the time for preparing core samples and measuring velocities in transversely isotropic (TI) rocks. Using this method, we have measured velocity and anisotropy of many shale and reservoir rocks from oil and gas fields around the world. We present some of the data in this paper, which include seismic velocity and anisotropy in 17 brine‐saturated shale samples, 1 gas‐ and brine‐saturated coal sample, 8 brine‐saturated sands, 12 gas‐saturated sands, 32 gas‐saturated carbonate samples, and 25 brine‐saturated carbonate samples. The results show that clays and fine layering in sedimentary rocks are the main causes of seismic anisotropy. Very little intrinsic anisotropy exists in unfractured reservoir rocks such as sands, sandstones, and carbonates under reservoir conditions. In contrast, all shales were found seismically anisotropic: anisotropy ranges from 6% to 33% for P‐waves and from 2% to 55% for S‐waves. The magnitude of shale anisotropy seems to decrease exponentially with increasing porosity. At present, the magnitude of shale anisotropy cannot be predicted accurately from other data without laboratory measurements. This paper also presents some best practices for laboratory measurements of shale velocity and anisotropy.

FCL-a Computerized Well-log Interpretation Process For the Evaluation of Naturally Fractured Reservoirs

Abstract The Fracture Completion Log (FCL) is a computerized process which allows the determination of primary and secondary porosity and water saturation in the primary porosity secondary porosity and composite systems. The process uses data from conventional well logs, such as resistivity density neutron and/or sonic. It has the advantage of detecting fractured systems even when the fractures are not intercepted by the borehole. This paper presents, the theoretical background behind the interpretation techniques, and examples of applications in the recompletion of an Austin Chalk well, and the completion of fractured carbonates in the Williston Basin of Montana and in Canada. Introduction Naturally fractured reservoirs are reservoirs which, in addition to primary or sedimentary porosity, contain secondary or induced porosity. Induced porosity is generated mainly by tension or shear stresses in a competent or brittle formation, diastrophism, volume shrinkage, solution, recrystalization, dolomitization and other geological processes. Figure 1 shows the location of some of the largest fractured reservoirs in the world. The ultimate recovery from currently producing naturally fractured reservoirs has been estimated at more than 40 billion barrels of oil. In spite of this attractive potential, fractured reservoirs had not received the attention they deserved until rather recently. Naturally fractured reservoirs behave significantly different from unfractured reservoirs due to the relative high capacity of the secondary porosity system. This high capacity allows high initial production rates which have led to extremely optimistic production forecasts and numerous economic failures. In order to understand the behaviour of naturally fractured reservoirs, estimates must be made of hydrocarbons-in-place within the primary and secondary porosity systems. A process (FCL) is presented which allows reasonable estimates of primary and secondary porosity, and water saturation in the primary, secondary and composite systems. This-process utilizes conventional well logs, such as resistivity, density, neutron and/or sonic. It has the advantage of detecting fractured systems even when the fractures are not intercepted by the borehole. The FCL cannot be considered as a panacea. However, it (figure in full paper) has provided excellent results in the evaluation, completion and recompletion of naturally fractured reservoirs in several places around the world. Principles The theoretical principles behind this process have been published previously in the literature by Aguilera(l-7) and have been used by others with reasonable success in Mexico(8), Venezuela(9,10) and the United States(11). In this process, the basic formation evaluation equations(12) Analysis of Eq. 1 indicates that a crossplot of porosity vs R1 on log-log coordinate paper should result in a straight line with a slope of -m for zones of constant a Rw and constant I. For reservoirs with secondary porosity, the value of m is smaller than the cementation exponent, mb, determined from a primary porosity sample in the laboratory at simulated reservoir overburden conditions or estimated from lithological descriptions. This is reasonable because secondary porosity results in a reduction in tortuosity and cementation. The value of m is determined by calculating the slope of the line drawn through the lower points in the plot.

Fracture Evaluation With Pressure Transient Testing in Low-Permeability Gas Reservoirs

Summary This paper presents theoretical and practical aspects of methods used to determine formation permeability, fracture length, and fracture conductivity permeability, fracture length, and fracture conductivity in low-permeability, hydraulically fractured gas reservoirs. Methods examined include Horner analysis, linear flow analysis, type curves, and finite-difference reservoir simulators. Introduction The purpose of this paper is to summarize the theoretical background of methods that we have attempted to use to determine formation permeability, fracture length, and fracture conductivity permeability, fracture length, and fracture conductivity in low-permeability, hydraulically fractured gas reservoirs. This summary is intended to emphasize the major strengths and weaknesses of the methods studied. These characteristics have not always been emphasized in the original literature and, in some cases, have remained obscure to the practicing engineer. The paper also includes examples from 13 wells in which postfracture-treatment pressure buildup surveys have been analyzed in detail. Test analysis methods discussed in the paper include (1) a method applicable only after a pseudoradial flow pattern is developed in the pseudoradial flow pattern is developed in the reservoir, (2) a method applicable when linear flow dominates in the reservoir, (3) published type curves, with emphasis on those that include finite- conductivity fractures, (4) a modification of linear- flow techniques useful for finite-conductivity fractures, and (5) use of finite-difference reservoir simulators in a history-matching mode. Pseudoradial Flow Pseudoradial Flow Russell and Truitt pioneered application of methods based on the assumption of pseudoradial flow in a fractured reservoir for determination of formation permeability and fracture length. A working permeability and fracture length. A working definition of pseudoradial flow is that sufficient time has elapsed in a buildup or drawdown test so that bottomhole pressure (BHP) varies linearly with the logarithm of flow time (drawdown) or the Horner time group (tp + delta t)/ delta t (buildup), as expected for radial flow in an unfractured reservoir. In an infinite-acting (unbounded) reservoir, the analysis technique is based on the use of skin factor, s, which can be calculated from (1) and the observation that, for infinitely conductive vertical fractures, (2) Eqs. 1 and 2 can be combined to avoid the intermediate step of calculating s: (3) In principle, we can plot buildup test data on a conventional Horner graph, determine the slope m, and thus estimate formation permeability (k = 162.6 qgBga mu a/mh) and determine fracture half-length, Lf from Eq. 3 (see Fig. 1). JPT P. 1776

Practicalities of Detecting Faults From Buildup Testing

The influence of a sealing fault (and other linear discontinuities) on transient well tests is a widely discussed subject. The topic first was presented by Horner for pressure buildup testing. Fig, 1 illustrates ideal pressure behavior in a tested well near a fault. This figure is a schematic semilog plot that applies to any kind of single-well transient test; doubling of the straight-line slope is the key to the existence of a fault. The material presented in this paper applies to falloff and buildup tests. It does not paper applies to falloff and buildup tests. It does not apply to flowing-only tests, such as drawdown, injectivity, and multiple-rate flow tests. The information in this paper assumes horizontal radial flow in a homogeneous, unfractured reservoir and assumes that wellbore storage effects are unimporant.There an pitfalls in detecting faults (used here to mean any linear discontinuity) from pressure buildup and falloff tests that generally are not recognized. The reason is that flow time determines how much reservoir a test investigates. So, for a pressure buildup test, the flow time before shut-in determines if it will be possible to recognize a fault from buildup data. If flow time is long enough, then the shut-in time need only be long enough to obtain data that show the dope doubling. A shortflow time cannot be compensated for by a long shut-in time. Interestingly enough, the pressure behavior caused by a fault is such that if shut-in time is not long enough to show the double slope, it is possible to interpret the data incorrectly as indicating a small closed system rather than a large system with a nearby fault.Flow times too short to detect faults during buildup testing are particularly apt to occur in two common types of well testing. One is drillstem testing, which generally has a short flow period. The second is the testing of a gas well where no pipeline facilities are available, so a short flow period is used while the shut-in period may last weeks or months.The theory describing pressure behavior in a well near a fault is relatively simple. Fig. 1 shows pressure buildup curve shape and indicates that the pressure buildup curve shape and indicates that the second slope, m2, is twice the first slope, m1. From the first slope, one calculates skin factor and permeability. permeability. The doubling of the slope is a strict theoretical requirement and not an approximation. P. 18

Determining the Elementary Matrix Block In a Fissured Reservoir Eschau Field, France

The fracturing of a reservoir is not a random phenomenon; it appears that the rock splits up into regular blocks bounded by networks of parallel fissures. A method is described for combining information parallel fissures. A method is described for combining information deduced from cores and outcrops to obtain a statistical distribution of fracture characteristics. From this we deduce the orientation, the dimensions, and the volume of the average block. Introduction In a fractured reservoir, recovery ratio and methods of calculating it are closely connected to the volume and size of the matrix blocks. The reason is that the volume and size of the block influence the way hydrocarbons escape from the rock matrix as the reservoir is depleted. This observation is valid for any depletion process, whether it be imbibition, solution gas drive, or gravity drainage. Furthermore, the orientation of blocks (which is derived from the orientation of bounding fractures) will greatly influence the flow of fluid toward the wellbore, and consequently will directly affect the location of production wells and the choice of recovery process, production wells and the choice of recovery process, both of which, in part, determine the recovery ratio. Various numerical simulation models have been designed to calculate future production, based on assumptions involving drainage mechanisms; basic to the functioning of the model are data on the characteristics of the matrix block. It would be highly desirable, then, to be able to gather data on the volume, size, and orientation of the matrix block for each well in a field. Such a goal can be achieved through production geology, because rock fracturing is not a random phenomenon, but takes place mainly under the effect phenomenon, but takes place mainly under the effect of tectonic stresses that accumulated with the rock mass during the geological history of the formation. In a study of the Laurel Gas Storage (Hocking County, Ohio), the U. S. Bureau of Mines noted that fracture orientation measured at an outcrop was similar to fracture orientation determined from oriented cores (taken at a depth of approximately 2,460 ft), and that hydraulic fracturing induced in an unfractured reservoir sample leads to a fracture orientation conditioned by the stresses that currently exist. The orientation of the induced fractures is superimposed upon that of the existing fractures. V.N.I.G.R.I. Institute of Leningrad (USSR) published similar observations based on data gathered published similar observations based on data gathered in the field from outcrops as well as on data derived from cores. From measurements of outcrops, the geologist can arrive at basic laws relating to the orientation and magnitude of fracture networks at major structural features, as both depend essentially upon tectonic stresses. The theories that now exist are general; and the laws behind them are only partly known; the theories may in some cases be used to classify into families all of the fractures encountered in cores, even if the outcrop corresponding to the subsurface structure being studied is actually missing. Subsurface observations made within a reservoir can thus be explained, and characteristics of the elementary matrix block can be determined. The aim of this study is to show, with a concrete example, the steps to take in determining the elementary, matrix block. The example is an application of a general method to a particular case. JPT P. 523

Alternate Producing and Gas Repressuring for Greater Oil Recovery

Abstract Considerations are presented to support a theory that alternately producing and repressuring a reservoir with gas will flush oil out of zones of low permeability in a reservoir under conditions in which conventional gas cycling would be relatively ineffective. Gas repressuring and batch gas cycling (alternately producing and repressuring) in semidepleted oil reservoirs may be a practical secondary recovery practice in many fields. Although this practice may not be as successful as water flooding in most shallow oil reservoirs, it holds considerable promise as a means of increasing recovery from deep reservoirs where water flooding would not be economically practicable. Batch-type gas cycling will sweep a greater part of a non-homogeneous reservoir than conventional gas cycling and therefore should result in a greater oil recovery. It can be used successfully where two or more reservoirs can be operated as a unit. Also, it can be used in a single reservoir if the reservoir is also used for gas-storage operations. This cycling procedure can be used successfully in reservoirs whose states of depletion range from newly developed oil fields to fields depleted by primary production. Introduction From a study of methods of predicting the performance of semidepleted oil reservoirs used for gas storage made recently by Bureau of Mines engineers, it was concluded that the amount of oil recoverable by repressuring and cycling a reservoir may be as great as that produced during primary recovery operations. It appeared also that the normal operations of a gas-storage project would generally gas-sweep a larger part of a reservoir than gas cycling at essentially constant pressure, especially in unfractured reservoirs with large variations in permeability. The flow of fluids in a reservoir used for gas storage differs from that in reservoirs subjected to gas cycling. In normal gas-cycling operations in non-homogeneous reservoirs the reservoir pressure is essentially constant, and the major flow of gas is through the more permeable zones. When a reservoir is used for gas storage, the oil-recovery operation may be in effect an alternate repressuring and partial depletion process.