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Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 13–17, 1999

Paper Number: PETSOC-99-32

... single water-oil contact. I have observed some instances where a single closed naturally

**fractured****reservoir**has two (and even three) different well-defined water oil contacts. This paper gives some ideas to how this can happen. The principles do apply to the case of multiple gas-oil contacts in a...
Abstract

Abstract Conventional wisdom developed throughout many years in the oil industry indicates that a single, closed reservoir can have only one single well-defined water oil contact. Although the contact could appear in some instances to be tilted because of capillary effects, it is still a single water-oil contact. I have observed some instances where a single closed naturally fractured reservoir has two (and even three) different well-defined water oil contacts. This paper gives some ideas to how this can happen. The principles do apply to the case of multiple gas-oil contacts in a closed reservoir, and could be applied in the case of non-fractured reservoirs. I present some guidelines to handle this problem in numerical simulation attempts. The reason is because most numerical simulators will raise an "error flag" if an engineer attempts to input more than one contact within the same simulation in a closed reservoir. Introduction The geological and engineering literature is full of examples showing that single closed reservoirs can have only one well-defined water-oil contact. In fact, the geological/engineering literature has mentioned that having a single water-oil contact is an indication that there is only one oil and/or gas reservoir. Having two or more well-defined water-oil contacts is our indication that there are two or more separate reservoirs. Due to the confidentiality of the data I have examined and the controversial nature of this paper, I have changed the name of the formations where I have observed this phenomena. CONVENTIONAL THEORY Figure 1 shows an example of multiple water-oil contacts (more than 20 WOC's) in separate reservoirs. The example was published on page 239 of Levorsen's book, Geology of Petroleum 1 , from where I quote: "Section through the Santa Fe Springs oil field, California, an example of how many separate traps, holding many separate pools, are formed by one fold. The lack of connection between the different reservoirs is shown in the different water-oil contact level for each productive sand." Figure 1 shows what is conventionally expected. Different water oil contacts in separate pools. But is it possible to have one single, closed reservoir and different water-oil contacts Figure 2A presents a well-accepted case of secondary hydrocarbon migration through the reservoir that does not necessarily end with the first trapping2. In stage one, gas, oil and water are segregated by gravity and all three phases are above the spill point. In stage two, oil reaches the spill point and migrates farther up-dip. In stage three, the anticline is filled with gas. Any oil migrating up at this time will bypass the trap entirely. Continuation of the same sequence of events throughout buoyancy will lead to the four traps in tandem presented in Figure 2B.This is a well-accepted case of multiple gaswater, gas-oil-water, and oil-water contacts in four traps connected with the same aquifer. The cross-section shown on Figure 3 is a corollary from the trapping concept presented in Figure 2 . Originally the trap is full with water. Oil migration occurs up-dip following the white arrow until it reaches level WOC1 close to the sealing fault.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–9, 1998

Paper Number: PETSOC-98-49

... Abstract Permeabilities from layer to layer can vary significantly in naturally

**fractured****reservoirs**. This study makes a comparison of geometric mean fracture permeability with permeabilities from well testing data in a layered naturally**fractured****reservoir**. The research was conducted with a...
Abstract

Abstract Permeabilities from layer to layer can vary significantly in naturally fractured reservoirs. This study makes a comparison of geometric mean fracture permeability with permeabilities from well testing data in a layered naturally fractured reservoir. The research was conducted with a model that contains 10 layers that are naturally fractured. The 10-layer model is validated by comparing its drawdown and buildup behavior against the behavior of a single-layer model. It is shown that permeability of the 10-layered reservoir calculated using a single-layer method will be much larger than the geometric mean and even the arithmetic mean, and will reflect the 2 layers with the largest permeabilities. If this is used in reservoir studies, it can lead to very optimistic forecasts. The problem of multi-layered permeability behavior may be recognized during a drawdown by a pressure derivative indicating partial completion effects even if the well is perforated in all fractured layers. During a buildup this recognition is more difficult because the shape of the buildup curve is affected by the length of the flow period previous to shutin. Introduction Outcrop information, imaging logs and production logs, have shown that in some cases naturally fractured reservoirs are composed by many layers 1 . The thinner the layer the smaller the fracture spacing (or distance between natural fractures). Under these circumstances some of the fractures might be intersected by the wellbore and some might not as shown on Figure 1 . A production log would show only the fluid entrance points into the wellbore. It is important to emphasize that the production log would not give an indication of net pay in the naturally fractured reservoir, only an indication of where the wellbore intersects the most important fractures. It is not unusual to see from a production log that out of 100 ft perforated in a fractured reservoir only 5 to 10 ft contribute production into the wellbore even if the 100 ft are true net pay. This is the result of a typical situation in most naturally fractured reservoirs I am familiar with, i.e., that the matrix has a very low permeability which does not permit efficient fluid flow into the wellbore. The same tight matrix, however, can flow very efficiently into the natural fractures 1 . One of the first papers dealing with pressure behavior of layered reservoirs was published by Leftkovits et al 2 . There was no communication between layers except at the wellbore. Later Russell and Prats 3 studied the practical aspects of interlayer cross flow, and concluded that the early time response would be similar to the response of a well draining a layered reservoir with no cross flow. Prijambodo et al 4 studied the early time performance of a well in a reservoir with cross flow and concluded that the pressure behavior was remarkably different from that of an equivalent single layer system. They indicated that the early time response could be divided in flow periods.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–9, 1998

Paper Number: PETSOC-98-21

... Abstract A mathematical model is presented to evaluate pressure response of a horizontal well in bounded homogeneous and naturals

**fractured****reservoirs**. The model also used to understand the pressure behavior of a horizontal well in an infinite acting, one, two or three sealing faults and...
Abstract

Abstract A mathematical model is presented to evaluate pressure response of a horizontal well in bounded homogeneous and naturals fractured reservoirs. The model also used to understand the pressure behavior of a horizontal well in an infinite acting, one, two or three sealing faults and closed rectangular Furthermore we introduce skin and wellbore storage in the numerical solution. Use of the technique is illustrated with the case of a horizontal well in a naturally fractured reservoir. Introduction As a horizontal well technology is becoming more suitable in developing naturally fractured reservoirs, tight reservoirs, heavy oil reservoirs and fine reservoirs. The pressure transient of horizontal well has become a very interesting topic. Many papers on well testing have been presented since Ramey's 1 and Gringarten's 2 review in 1982 and 1984, The earlier articles are about reservoir performance and productivity of horizontal well. 4,5 In recent years, the paper deals with pressure distribution of horizontal well for homogenous and naturally fractured reservoirs 6–8 . Most recently, a number of papers have cared for the interpretation of horizontal well test data and horizontal well-layered reservoir and multi-lateral well. 3,13,14 Unlike vertical wells, reservoirs have to be seen as three-dimensional formations. Hence, the pressure behavior of a horizontal well is more sophisticated than that of a vertical well. Transient behavior is an important factor in understanding the horizontal well performance. Although Mathematical modeling of horizontal wells is abundant in the literature, seldom papers pay attention to boundaries including rectangular, channel, parallel, one fault and computational method. Only recently several papers appear to discuss boundaries case 3,10,11,13 , R. Aguilera and M.C. Ng 3 using the method of images, handle wellbore storage and skin in pressure drawdowns and buildup of vertical well in bounded rectangular naturally fractured reservoirs. Tompson et al 13 , on the other hand, deals with double porosity reservoirs for horizontal well, also through Laplace transform. Ozkan's approach 10–12 is very good method to handle complex boundaries, This paper uses this method to generate pressure response of horizontal Well under different boundaries, including infinite, single faulted, parallel, channel, and closed rectangular homogeneous and naturally fractured reservoirs. Theory Let us consider a horizontal well completed in an anisotropy medium, which is infinite in the × and y directions. kx, ky and kz denote the perrneabilities of the formation in the principle directions. Although solutions have been presented for the three-dimensional anisotropy medium, we will deal with the solution for isotropic media (k h = k x = k y and k v = k z ). We consider the flow of a single-phase, slightly-compressible fluid of constant viscosity and a horizontal well has length L in a reservoir of height h. The upper and bottom boundaries (z=O and z c =h) are assumed to be impermeable. The well is assumed to be parallel to the top and bottom boundary, and gravity effects are considered to be negligible. The origin of the coordinate system, as shown in Figure 1, is the center of the well. Initially, the pressure is uniform throughout the reservoir. For convenience, we use results in dimensionless form. Dimensionless pressure and dimensionless time are defined as:

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–10, 1997

Paper Number: PETSOC-97-107

... Abstract The using of horizontal wells is an effective exploitation way for naturally

**fractured****reservoirs**. In accordance with horizontal wells in a naturally fractured volcanic reservoir, the characteristics of damages from drilling, completion and natural blockages are discussed and the aim...
Abstract

Abstract The using of horizontal wells is an effective exploitation way for naturally fractured reservoirs. In accordance with horizontal wells in a naturally fractured volcanic reservoir, the characteristics of damages from drilling, completion and natural blockages are discussed and the aim of acidizing is outlined in this paper. The method to determine segment length and position and treatment parameters are presented for segment acidizing. The three-dimension unsteady acid flow model, acid flow heat exchange model and acid-rock reaction model are established and a semi-numerical calculating method is utilized in order to simultaneously predict the distribution of acid velocity, temperature and concentration during acidizing treatments. The well completion and the segment acidizing design are presented for a horizontal well in a naturally fractured volcanic reservoir of a oil field in western China. Introduction Horizontal wells have been widely used in petroleum industry [1][2] because they have higher economic efficiency and advantages over vertical wells such as controlling sand, delaying gas or water coning and preventing turbulent flow around the wellbore etc.. They are very attractive to be used to exploitate anisotropic reservoirs [2] like naturally fractured reservoirs, because they have more opportunities to channel through fractures as natural fractures are generally vertical and they have longer wellbores in pay zone. However, the formation damage will be more severe in horizontal wells than in vertical wells because of the longer exposure time and higher mud density to maintain the stability of bore hole. The damage impact on the production index of horizontal wells has been investigated [3][4] . The results shows consequence matrix stimulation treatments are required to increase the flow profile across horizontal section. The use of coiled tubing is the recommended method for the matrix stimulation of horizontal wells as it can provide a necessary mechanical isolation and diversion for uniform coverage along a horizontal well [5] . The optimal rate of coiled tubing withdrawal was given by Economides et. al. [4][5] for matrix acidizing of horizontal wells. As coiled tubing stimulation can not exercise a well effect in naturally fractured reservoirs where diverters would lose their functions another acidizing method such as segment acidizing should be used. This paper presents design method of segment acidizing and treatment consideration for horizontal wells in a naturally fractured volcanic reservoir. The provided method may be applied in other naturally fractured reservoirs as carbonate reservoirs. RESERVOIR CHARACTERISTICS The studied reservoir was produced by paroxysmal eruption and its rock is mainly vitric and sedimentary tuff with frequently natural fractures of middle to high angles. The fractures have width of 0.5-5.0mm according to the core investigation and are seriously filled with calcite, float stone and chlorite etc.. The reservoir is driven by dissolved gas. The other parameters of the reservoir are shown in table 1. Horizontal wells were selected to develop this reservoir after compared the economical efficiency of horizontal wells with that of vertical wells. FORMATION DAMAGE There are two main damage sources for horizontal wells in naturally fractured reservoirs. One source is natural blockages in fractures, which were produced while they were formed and the other is from drilling, completing, workover and producing.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–10, 1997

Paper Number: PETSOC-97-33

... composition profile around the wellbore at shutin. Introduction Naturally

**fractured****reservoirs**have been the object of intensive research during the last few years in the geologic as well as the engineering fields. Transient pressure analysis has received particular attention. Barenblatt and Zheltov (1...
Abstract

Abstract Approximate equations are presented for evaluation of naturally fractured gas condensate reservoirs represented by dual-porosity models in radial systems. The reader is cautioned that this work is in progress. Additional research will help to corroborate and refine these techniques. The solutions have not been published previously in the petroleum engineering literature. The solutions are presented for drawdown and buildup tests. The model assumes flow of gas condensate from a tight matrix into permeable natural fractures. The fractures conduct the fluids to the wellbore. It is preliminary shown that a conventional cross plot of m(p) vs. time on semi logarithmic coordinates results in approximately two parallel straight lines with a separation that is related to the storativity ratio between fractures and matrix. This plot allows determination of key parameters such as absolute permeability, effective permeability's to oil and gas, skin, storativity ratio (ω), fracture porosity (Φ 2 ), average distance between natural fractures (h m ), radius of investigation, and extrapolated pressure (p 1 or p). In addition the method permits generating a liquid saturation profile and a general composition profile around the wellbore at shutin. Introduction Naturally fractured reservoirs have been the object of intensive research during the last few years in the geologic as well as the engineering fields. Transient pressure analysis has received particular attention. Barenblatt and Zheltov (1) and Warren and Root (2) handled naturally fractured reservoirs by assuming pseudo steady-state (restricted) interporosity flow in a model made out of cubes with spaces in between. Flow toward the wellbore was assumed to be radial via the natural fractures. Their work led to the conclusion that a conventional cross plot of pressure vs. log of time should result in two parallel straight lines with a transition period in between. The separation of the two straight liens allowed calculation of the storativity ratio omega, i.e. the fraction of the total storage within the natural fractures. Kazemi (3) used a numerical model of a finite reservoir with a horizontal fracture under the assumption of unsteady state interporosity flow and substantiated Warren and Root's conclusion with respect to the two parallel straight lines. The transition period, however, was different due to the unsteady rather than pseudo steady-state interporosity flow assumption. de Swaan (4) developed a diffusivity equation and analytical solutions to handle the first and last straight lines. His method, however, could not analyze the transition period. Najurieta (5,6) developed analytical solutions of de Swaan's radial diffusivity equation which could handle the transition period as well as the first and last straight lines. Streltsova (7) used a gradient flow model and indicated that the transition period should yield a straight line with a slope equal to ½ the slope of the early and late straight lines. Her examples showing the ½ slopes gave values of storativity ratios approximately equal to 0.37, 0.26, and 0.48. Serra et al. (8) reached the same conclusion with the use of a stratum model for the cases in which the storativity ratio, omega, was smaller than 0.0099. Various type curves have been developed to analyze naturally fractured reservoirs with transient (9,10) and pseudo steady-state (11) interporosity flow.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–10, 1997

Paper Number: PETSOC-97-57

... Abstract The author has worked on a number of

**fractured****reservoirs**in Western Canada, which show a number of common characteristics. Evaluating this type of pool is normally very complex and presents a number of difficulties. Production performance is discussed. They also exhibit distinct...
Abstract

Abstract The author has worked on a number of fractured reservoirs in Western Canada, which show a number of common characteristics. Evaluating this type of pool is normally very complex and presents a number of difficulties. Production performance is discussed. They also exhibit distinct types of pressure transient response, which do not correspond to Warren and Root type dual porosity description. Stimulation results have proven difficult to predict. A reservoir characterization is presented which is consistent with observed production performance, pressure transient responses, production logging results, core analysis and well stimulation. A key component is structural geological style. This description has been applied to a number of different reservoir situations. It has application to stimulation design, predicting reservoir performance, numerical simulation and pressure transient analysis. An example is highlighted for a gas condensate reservoir. Introduction The material in this paper was derived from a number of large detailed reports. Such a detail and volume of material cannot be covered in a single technical paper. The paper therefore only presents a summary of a number of key concepts derived based on the author's experience. The following is discussed: Systematic Approach Core Descriptions Structural Style Fracture Patterns Effect Of Stress Discrete Element Analysis Pressure Transient Observations Mechanisms Example Application: Gas Condensate This paper is complemented with a companion paper 1 "Optimization of the Blueberry Debolt Oil Pool: Significant Production Increases for a Mature Field", which is also presented at this conference. Systematic Approach Evaluating a fractured reservoir (after Nelson 2 ) involves four main steps: Interpreting the origin of the fracture system. This information allows one to predict geometry and the extent of communication. Determining petro-physical properties of the fractures and matrix. This allows for prediction of the variation in reservoir response. The relative storage (i.e. porosity) must be determined as well as effective permeabilities. Another important property is compressibility. The flow interaction between the matrix and fracture system is evaluated to determine ultimate reserves from the reservoir. Classification of the reservoir. Depending on the type of flow interaction the reservoir will fit one of several depletion strategies. Note that most of the variations in strategy apply to waterflooding oil reservoirs. Conventional Core Analysis To obtain most of the base information requires some basis of observation, which for most reservoirs starts with core. Information can be derived from the following conventional core analysis data and plots: Core permeability vs core porosity - all data. Core permeability vs core porosity - sorted by lithology. Vertical permeability vs horizontal permeability. K90 plotted vs Kmax. Fractured reservoirs do not show the typical straight line relation on core permeability vs core porosity (semilog) plots. Typically lower porosity rock is more prone to fracturing. Fractured reservoirs also tend to have higher anisotropy, which is seen as large variation in K90 vs Kmax. Core Description Example From Central Foothills In the author's experience, based a number of studies in Western Canada, there is a typical core permeabiliy vs core porosity relati

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–10, 1997

Paper Number: PETSOC-97-31

... Abstract A newly developed mathematical model has been used for formation damage analyses of two hydraulically fractured horizontal wells in the Daqing field, China, and twelve vertical wells in the naturally

**fractured****reservoirs**of the Spraberry Trend Area, West Texas. Application of the...
Abstract

Abstract A newly developed mathematical model has been used for formation damage analyses of two hydraulically fractured horizontal wells in the Daqing field, China, and twelve vertical wells in the naturally fractured reservoirs of the Spraberry Trend Area, West Texas. Application of the model to Daqing horizontal wells indicated that these wells should have 4 to 5 times higher oil production rates if the formation was not damaged The use of the model has captured the characteristics of rapid decline in productivity of the Spraberry vertical wells. Comparisons between the effects of matrix skin and fracture permeability indicated that stress sensitive fracture permeability is responsible for the productivity loss of these wells. This paper provides reservoir engineers with a practical tool for analyzing inflow performance of wells intersecting long fractures. Introduction The Spraberry Trend Area of West Texas was discovered in 1949 and was considered the largest field in the world. The Spraberry Trend Area presents unusual problems for both primary production and waterflooding. After more than 40 years of waterflooding, the current oil recovery is still less than 15 per cent. A model study of a waterflood pilot in the Spraberry Trend Area indicated a NE-SW trend of the major Fractures l . A contrast of 144/1 was required for the major/minor fracture trend permeability ratio to match the pilot response. This strong anisotropic effective permeability implies the existence of well inter-connected, long natural fractures in the Spraberry reservoir. A characteristic of flow in the long natural fractures is the pressure variation along the fracture should be significantly higher compared to that in a hydraulic fracture or a short natural fracture. Unfortunately, a method for analyzing flow behavior in reservoirs with long fractures is not readily available from the literature. Several analytical solutions have been presented for transient flow in fractured reservoirs. 2–8 Numerical models have also been developed for simulating fluid flow in fractured reservoirs. 9,10 However, it is still desirable for reservoir engineers to use steady flow equations for identification of formation damage in the fractured reservoirs. This is not only because the analytical transient flow solutions and numerical simulators are not convenient to use, but also because steady or pseudo-steady flow prevails as the dominating flow mechanism in the lifetime of most oil wells. Therefore, steady flow equations are attractive for formation damage analysis. This paper demonstrates applications of a newly developed steady-flow mathematical model for formation damage identification. This model is utilized for analyzing performance of two horizontal wells with hydraulically induced fractures in the Daqing field, China, and twelve vertical wells intersecting natural fractures in the Spraberry Trend Area, West Texas. Use of the model for matching production data aided in understanding of the productivity of the Daqing horizontal wells and the unusual behavior of Spraberry Trend Area reservoirs. The results of analysis for the Daqing horizontal wells indicate that these wells should have higher potential if formation damage could be removed. The use of the model has captured the characteristics of rapid decline in productivity of Spraberry vertical wells.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 9–11, 1996

Paper Number: PETSOC-96-60

... 4 – 5 pseudo components for the simulations. It also discusses the condensate dropout in the reservoir and its effect on the productivity of individual producing wells. The methods for characterizing fracture networks in a naturally

**fractured****reservoir**are presented and other parameters which affect...
Abstract

Abstract Recent improvements in the speed of numerical compositional simulators has made it possible to use a large number of gridblocks to model condensate reservoirs, volatile reservoirs, and gas injection projects. This paper discusses techniques for choosing pseudo components so as to use 4 – 5 pseudo components for the simulations. It also discusses the condensate dropout in the reservoir and its effect on the productivity of individual producing wells. The methods for characterizing fracture networks in a naturally fractured reservoir are presented and other parameters which affect hydrocarbon recovery are discussed as part of a parametric study. INTRODUCTION In recent years wells have been drilled to greater depths, resulting in the discovery of gas condensate reservoirs and volatile oil reservoirs at relatively high temperatures. Recently a large amount of research has been conducted to investigate productivity from these oil reservoirs. This research has investigated how to tune an equation of state so as to match the actual phase behavior which is occurring within a reservoir. Studies have reported on the effects of interfacial tension and velocity on gas-oil relative permeability curves. These studies indicate that bench type gas-oil and water-oil relative permeabilities are not applicable to predicting the performance of individual wells in gas condensate reservoirs. Well test data and recent advances in well logging procedures using well-bore imaging techniques have provided tools to better characterize the fracture system which exists in naturally fractured reservoirs. These data have been used in conjunction with stochastic models to describe the fracture network inside of these reservoirs. A parametric study using a number of variables was conducted for this paper. The results from this parametric study are useful in history matching to determine those parameters which, when adjusted, will have the greatest effect on the performance of the reservoir. This study will also suggest modifications which need to be made to numerical simulators so as to better simulate the actual mechanism which are occurring in gas condensate reservoirs. MECHANISM OF FLOW IN NATURALLY FRACTURED RESERVOIRS Fluid flow in naturally fractured reservoirs differs significantly from that in a single porosity system. The numerical simulator breaks the reservoir into two different systems, one a system of matrix blocks which mayor may not have capillary contact and a network of fractures. The simulator basically assumes that most of the flow to the wells will occur through the fracture network which contains a relatively small fluid volume, but high permeability, and that the bulk of the hydrocarbon fluids are contained within the matrix blocks. As reservoir pressure is depleted, the fluids are expelled from the blocks into the fracture system which conveys them to the producing wells. Gas condensate reservoirs initially are at pressures at or above the dewpoint. Once the pressure has been depleted below the dewpoint, liquid will condense and two phases will be present. Once these two phases are present the liquid will not flow in either the matrix or the fracture system until a critical condensate saturation is obtained.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 9–11, 1996

Paper Number: PETSOC-96-21

... Abstract A systematic methodology which combines inflow performance analysis, production forecasting, and economic considerations is presented for optimum recovery of hydrocarbons from naturally

**fractured****reservoirs**using horizontal well technology. An analytical method for predicting the...
Abstract

Abstract A systematic methodology which combines inflow performance analysis, production forecasting, and economic considerations is presented for optimum recovery of hydrocarbons from naturally fractured reservoirs using horizontal well technology. An analytical method for predicting the production performance of horizontal wells in a solution gas drive, naturally fractured reservoir is presented based on material balance analyses and linear approximations of reservoir fluid properties as functions of reservoir pressure. The effect of natural fracture characteristics on production performance is accounted for by use of the inflow performance equations derived and presented in a previous paper. A detailed economic evaluation model accounting for the time value of cash flow, including the effects of interest rate and inflation rate, is also presented and used in the analysis. Results are presented which demonstrate the methodology developed and its application to the optimum primary recovery from a naturally fractured solution gas drive reservoir using horizontal well technology. In addition, the methodology is also applied to the case of a gas well producing from a horizontal wellbore intersecting discrete natural fractures. This paper includes the development of a new production forecasting method, the identification of the criteria for determining an optimum drilling and reservoir managementscheme, and the demonstration of their applicability in optimizing the recovery from a naturally fractured reservoir using horizontal well technology. INTRODUCTION Over the past two decades considerable interest has been focused on the utilization of horizontal well technology to improve the recovery of hydrocarbons from natural fractured reservoirs. This interest has resulted in the publication of numerous papers concerned with all aspects of drilling, completing and producing horizontal wells. However, an extensive literature review (l) indicated that systematic techniques have not been developed to optimize the recovery of hydrocarbons from such complex reservoirs utilizing horizontal well technology. The current industrial practice still relies primarily on the basic knowledge of fractured systems and on practical experiences for determining the orientation, length, and spacing of horizontal wells. More recently Guo and Evans (2–6) have published several papers which focused upon many important aspects of a horizontal well bore intersecting discrete and/or randomly distributed natural fractures. These papers have developed techniques for characterizing natural fractured reservoirs, pressure transient testing, production forecasting, and economic evaluation. From this research a systematic methodology has evolved which can be used to maximize the recovery of hydrocarbons from a naturally fractured reservoir utilizing horizontal wellbores. To maximize the recovery from naturally fractured reservoirs using horizontal well technology requires: a quantitative characterization of the natural fracture system so that the proposed horizontal wells can be drilled orthogonally intersecting the natural fractures; appropriate inflow performance equations for a horizontal well intersecting natural fractures to estimate the well productivity; a production forecasting technique to predict production performance of naturally fractured reservoirs; and an economic evaluation model for assessing the feasibility of exploiting naturally fractured reservoirs using horizontal well technology.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 6–8, 1995

Paper Number: PETSOC-95-12

... Abstract An analytical composite model using non-linear least square regression technique for estimation of real parameters of naturally

**fractured****reservoirs**, utilizing well test data is presented. The problem of alteration of fracture properties due to acidizing or damage called by drilling...
Abstract

Abstract An analytical composite model using non-linear least square regression technique for estimation of real parameters of naturally fractured reservoirs, utilizing well test data is presented. The problem of alteration of fracture properties due to acidizing or damage called by drilling fluid is taken into account by introducing two concentric media of different fractures. In this work correlations amongst fracture permeability and porosity, ω, λ, skin factor and matrix block size together with field examples are also presented. Introduction The double porosity models presented by Barenblatt et al l and many others 2–4 treat naturally fractured reservoirs by superimposing two continua, One for the fracture system and another for the porous matrix. The flow of fluid in the fracture system toward the wellbore is assumed to be radial. This holds only for infinisimal matrix block dimensions. For real cases where the matrix blocks are of finite dimensions, several fee~ the flow in the fractures near the wellbore is linear. It has been shown 5 that the pressure drop in the fractures with linear flow is less than the pressure drop caused by a radial system with a bulk permeability identical to that of the fractures. This is why the analysis of well test data obtained from naturally fractured reservoirs usually show negative skins by semilog analysis. The flow behavior of a two dimensional fracture network with nonporous identical parallelepiped matrix blocks under steady state conditions 5 has shown that the negative skin is proportional to the logarithmic of the matrix block size and the flow system starts exhibiting radial flow behavior from a radial distance of one matrix block from the wellbore. Drilling and workover operations may alter the width of the fractures around the wellbore resulting in two damaged and undamaged zones. The damage zone may be assumed circular and the fractures in this zone of uniform thickness. In order to study the behaviour of the flow system with the above mentioned features a composite model consisting of three regions is considered. Composite systems have been the subject of considerable attention in the petroleum literature. In general, the composite model consists of a well completed in the centre of a circular inner region with fluid and rock properties different from those in an outer region. This approach has been used to study interference between oil fields in a common aquifer of different permeabilities6. A two region composite model has been used to study the behavior of wells intersected by fractures extending over a limited area 7 , It also has been used to study the behavior of wells intersected by infinite conductivity vertical fracture in dual porosity reservoirs 8 . In this work a general flow equation for a composite system consisting of three (inner, intermediate and outer) regions is presented to describe the near wellbore linear flow and the outer radial flow in the two damaged and undamaged regions.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 6–8, 1995

Paper Number: PETSOC-95-80

... fracturedreservoirs. Recently, at the University of Wyoming laboratory studies of this littleexplored research area of steam flooding in

**fractured****reservoirs**with thepurpose of understanding the basic mechanisms that control the recoveryprocesses were performed 2 , 3 , 4 , 5 .The results obtained from these...
Abstract

Abstract A novel steam-CO 2 combination flooding process for oil recovery hasbeen investigated systematically using a specially designed experimentalsystem. Numerous experiments have been performed using both non-fractured and fracturedsandstone cores. The experimental results from non-fractured and fracturedsandstone cores are very encouraging. The oil recovery increased as much as 20%for non-fractured cores and 18% for fractured cores of original oil in place bysteam-CO 2 process compared to steam-alone process. In addition to the effects of injection temperature and injection rates on oilrecovery and irreducible oil saturation, the ratio of steam overCO 2 , a dimensionless number, was found to dominate the oil recoveryprocess. In non-fractured sandstone cores, there exists an optimum ratio ofsteam over CO 2 which yields a maximum oil recovery with the lowestirreducible oil saturation. The ratio does not depend on injection temperatureand injection rates. In fractured cores, there still exits an optimumsteam-CO 2 ratio which yields a maximum oil recovery with lowestirreducible oil saturation. However, it depends on injection temperature. The theory to explain this novel steam-CO 2 flooding process stillneeds further study, some fundamental mechanisms which contribute to theprocess have been investigated in our research. Introduction Naturally fractured carbonate reservoirs represent a unique target for theapplication of enhanced oil recovery (EOR) technology. High divalent ionconcentrations in reservoir water and extensive fracture networks discouragethe use of chemical and miscible processes with possible exception of miscible CO 2 . Because of channeling of injected air, in-situ combustion wouldbe difficult to sustain 1 . For non-fractured eservoirs steam floodingis a proven and commercially process for oil recovery (especially heavy oil).Its recovery mechanisms are so well identified that design and operation ofthese methods are successfully implemented. The state of understanding andtechnology is quite controversial in case of using the process for fracturedreservoirs. Recently, at the University of Wyoming laboratory studies of this littleexplored research area of steam flooding in fractured reservoirs with thepurpose of understanding the basic mechanisms that control the recoveryprocesses were performed 2 , 3 , 4 , 5 .The results obtained from these studies have been very encouraging n terms ofanswering the questions about the important process mechanisms controlling therecovery oil from fractured sandstone cores. For homogeneous (non-fractured) reservoirs, laboratory studies and fieldreports 6 , 7 , 8 , 9 , 10 , 11 , 12 indicated that the use of certain additives(carbon dioxide nitrogen, flue gases, caustic, etc.) with steam could resultin improvement in oil recovery. These observations lead us to believe that theeffects of additives to steam flooding of fractured reservoirs would be veryuseful investigations for improving the success of steam flooding processes infractured reservoirs. The existing steam flooding system was combined with facilities of injectingadditives (CO 2 Nitrogen, etc.), By using this new experimentalapparatus, numerous experiments were performed both in the non-fractured andfractured sandstone cores. This paper summarizes the related research and fieldtest results. The experimental details as well as the results ofsteam-CO 2 flooding in fractured

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 6–8, 1995

Paper Number: PETSOC-95-94

... and fractures is of specialimportance to mathematical modelling of

**fractured****reservoirs**(Aronofsky et al.,1958; Warren and Root, 1963; Kazemi et al., 1976; Kazemi et al., 1992, Chen etal., 1995) Scaling of spontaneous imbibition henomena is a critical step inthis development. Provided that gravity...
Abstract

Abstract Scaling of spontaneous imbibition measurements is important to characterizationof wetting properties and to modelling mass transfer between rock matrix andfractures. A scaling equation proposed by Malrax and Kyre (1962) has beenwidely applied to prediction of field-scale oil recovery rom fracturedreservoirs. The scaling equation involves many assumptions including identicalcore-sample shapes and viscosity ratios. In this paper, the effect o/viscosityand viscosity ratio on rate of spontaneous imbibition is investigated.Imbibition data is reported for systems with two orders of magnitude variationin viscosity ratio. The results show, for systems of similar geometry, that theimbibition time is proportional to the square root of viscosity ratio. Thisobservation combined with a new definition of characteristic length is used todefine a modified scaling group which allows for differences in viscosityratio, and the shapes and boundary conditions of the coresamples. Introduction Spontaneous imbibition is a natural physical process driven by capillary forceswhereby a nonwetting phase is displaced by a wetting phase from a porous medium(Morrow, 1970). Examples of practical significance may be found in civil andchemical engineering, soil science, and numerous other areas. In petroleumengineering, imbibition is considered especially important in oil recovery fromfractured eservoirs, where the rate of mass transfer between rock matrix andthe associated fractures controls the oil production. However, much remains tobe learned about the combined effect of imbibition, gravity, and bothmicroscopic and macroscopic fluid distribution on oil recovery from fracturedsystems. Development of analytical functions or other computational schemeswhich account for mass transfer between rock matrix and fractures is of specialimportance to mathematical modelling of fractured reservoirs (Aronofsky et al.,1958; Warren and Root, 1963; Kazemi et al., 1976; Kazemi et al., 1992, Chen etal., 1995) Scaling of spontaneous imbibition henomena is a critical step inthis development. Provided that gravity effect can be safely neglected, capillary pressure is the driving force for spontaneous imbibition.Permeability and relative permeabilities in the two phase region of flowdetermine the rate of imbibition. Both capillary pressure and relativepermeability are functions of saturation. Thus many factors enter into scalingof imbibition rates. The effect of fluid viscosity is of primary concern inthis study. The effect of core sample shapes and boundary conditions will alsobe discussed. Imbibition In Tubes Most analyses of imbibition consider behavior in cylindrical tubes. For acylindrical tube of radius r, the Laplace equation gives the capillarypressure, P C P C = Equation (1) Available in full Paper where s is the interfacial tension and ? is the contact angle. The relationship between permeability, k, porosity, f and tortuosity, tfor aparallel bundle of equal size cylindrical tubes with radius r is given by Leverett (1939). r = Equation (2) Available in full Paper Thus the capillary pressure, Eq 1, can be expressed as P C = Equation (3) Available in full Paper The ratio of permeability to pore size gives a characteristic pore structurelength

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 11–14, 1994

Paper Number: PETSOC-94-16

... for r inv . Note: The paper is missing text between pages 4 and 5. This is the version included in the proceedings. It is priced free of charge. state model investigation laplace transform matrix fracture system conductivity reservoir drillstem testing

**fractured****reservoir**petroleum...
Abstract

Abstract The reservoir parameters obtained from any transient pressure analysis, reflect average values of the characteristics of the area around the well that has experienced a pressure disturbance due to the change of flow rate at the wellbore. This area is described by an associated radius called the radius of investigation. In the authors&apos; knowledge, no work has been done to examine this radius in fractured or dual porosity reservoirs. This paper describes a new equation for evaluation of the radius of investigation for well tests in such reservoirs under pseudosteady state interporosity flow regime. The results have shown that the radius of investigation in such reservoirs starts increasing in the fracture network proportional to the square root of the fracture conductivity. When the matrix contribution to the flow of fluids starts the rate of advance of the radius decreases until its magnitude reaches a maximum value and remains constant until the total system stabilizes. After this time the radius increases again with a lower rate dependent now on the total system conductivity. Introduction The radius of investigation also called the radius of influence or radius of drainage is defined in many ways by several authors 1,2,3.4.5,6 . In most definitions this radius determines a circular system with a pseudo-steady state pressure istribution around the wellbore, and takes the form as follows: Equation (1) Available In Full Paper where A is a constant and r inv is the radius of investigation. If the start of semi-steady state flow for a homogeneous and symmetrical bounded cylindrical reservoir at a time t De of 0.3 is used, and the parameters are defined in oil field units where, r inv is in feet, t is the time of flowing for a drawdown test or the time of shut-in when Δtp for a buildup test in hrs., K is the formation permeability in mds, φ is the reservoir porosity in fraction and c is the total system compressibility in psi −1 , the constant A becomes 0.029. Odeh and Nabor 7 , by using an RC analyzer obtained A to be 0.0257, and Kazemi 8 from the numerical finite difference solution obtained it to be 0.035. Hurst et al 3 , Van Poolen 5 and Slider 9 separately used the concept of unsteady state radial flow to find out when to switch from infinite acting solution to finite solution of the homogeneous diffusivity equation. By taking the derivative of the difference between the above solutions with respect to time and putting it equal to zero the flowing equation for radius of investigation will be obtained: Equation (2) Available In Full Paper Matthews and Russell 10 picked a time t De of 0.25 intermediate to the two times corresponding to the end of infinite acting and the start of semi-steady state, and obtained the same Eq.2. Muskat 1 , Chatas 11 and Craft and Hawkins 12 by equating the volume of the fluid produced to the expansion of the fluid contained in the drainage area and by considering steady state conditions also obtained the same Eq. 2 for r inv . Note: The paper is missing text between pages 4 and 5. This is the version included in the proceedings. It is priced free of charge.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 11–14, 1994

Paper Number: PETSOC-94-79

... and fluidproperties. The results indicate if the very low matrix permeability contributes tohydrocarbon production in the naturally

**fractured****reservoir**where the core wascut. Introduction There are many naturally**fractured****reservoir**around the world in all kinds oflithologies throughout the...
Abstract

Abstract A common question when dealing with tight matrix naturally fracturedreservoirs is - How can we determine if the matrix is contributing tohydrocarbon production? One source of information for helping to answer thisquestion is provided by matrix and fracture permeabilities determined with thePressure-Decay Profile Permeameter (PDPP). The useful range of the tool is from0.001 to 20,0000md. These permeabilities are corrected for overburden conditions and are utilizedto numerically simulate the interaction between matrix and fractures in a core.The procedure involves the following steps: From PDPP measurements create iso-permeability maps of the fracturecore. Discretize the permeabilities using a micro-gridover the core area. Select a ‘production’ cell in the fractures and various observation cellsin the matrix. Simulate the core using reservoir pressure, temperature and fluidproperties. The results indicate if the very low matrix permeability contributes tohydrocarbon production in the naturally fractured reservoir where the core wascut. Introduction There are many naturally fractured reservoir around the world in all kinds oflithologies throughout the various geologic periods. This type of reservoirscontains significant amounts of oil and gas resources. They presents botheconomic opportunities and technical challenges. Inorder to properly exploitnaturally fractured reservoirs, engineers and geologists have developedspecialized techniques and tools to help in their evaluation. The overview of the characteristics of naturally fractured reservoirs andtechniques for their analysis have been the subject of various textbooks 1–5 . In a paper on recent advances in the study of naturallyfractured reservoir, Aguilera 6 summarizes the sources of informationavailable to evaluate naturally fractured reservoirs. In a very simple model, a naturally fractured reservoirs consists of matrixrock with high storage and low permeability. These matrix rock is generally notcapable to sustain commercial production without natural fractures. Thefractures have very low storage capacity but high permeability. Fluid in thematrix can bleed off into the fracture network and then be transported throughthe ractures to the wellbore. An often asked question is whether fluid storedin the tight matrix actually contribute to production. A new technique forpermeabilitymeasurements in cores coupled with numerical microsimulation offerssome answers to this question. This could be combined with a laboratory technique that allows to measureseveral hundred pressure readings in a short span of time to study the responseof cores to pressure disturbances. This laboratory technique allows quick andaccurate determination of matrix and fracture properties as reported by Kamathet al. 7 Fractured core properties A carefully handled core from a naturally fractured reservoir provides valuableinformation on reservoir properties, including whole core porosity andpermeability. From well logs we can estimate porosity in the matrix, andractures. Pressure transient analysis can also add information includingfracture porosity and permeability. All these estimates are related to the bulkproperties of the system. With a new permeability measuring equipment, thepressure-decay profile Permeameter 8–10 , detailed description ofpermeability distribution can be obtained.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 11–14, 1994

Paper Number: PETSOC-94-64

.... Findings of this study can be used in the area of modelling steam injection in heavy oil

**fractured****reservoirs**, .e. heat consumption by matrix blocks in the steam zone can be modeled using analytical solutions of heat conduction For physical properties other than those considered in this paper, evaluation...
Abstract

Abstract Steam injection into fractured vugular formations is of great importance in Alberta, as well as in several countries in the Middle East. In Alberta alone, over one trillion barrels of oil occur in the Grosmont formation, where oil recovery would be possible only through steam injection into vugs and cavities. In spite of the importance of this problem, a solution is still lacking, and the few proposed approaches lack consistency or are based on conflicting assumptions. The present paper mathematically examines the governing equations in conduction healing - in particular, two of the more controversial premises, viz. the importance of the unsteady-state term and the assumption of a moving vs. a stationary boundary for a single block in the steam zone. This is accomplished analytically, first by means of a magnitude analysis, and next through a solution of the partial differential equations involved. It was found that any analysis of the fracture heating problem must retain the unsteady-stale term, and that the use of the moving boundary is superfluous in low mobility systems. It is shown that the convective term is two orders of magnitude smaller than the diffusive term. Findings of this study can be used in the area of modelling steam injection in heavy oil fractured reservoirs, .e. heat consumption by matrix blocks in the steam zone can be modeled using analytical solutions of heat conduction For physical properties other than those considered in this paper, evaluation of the Peclet No. indicates the order of error that will be introduced if convection is neglected. Introduction Heavy oil occurring in carbonate reservoirs, mostly fractured, is an important resource, which accounts for one third of total heavy oil world-wide 1 . In Alberta alone, over one trillion barrels of bitumen occur in the carbonate Grosmont formation, where the existence of fractures enables injection into the reservoir 14 . Processes like steam injection, or other thermal recovery methods, which have been used extensively to recover heavy oil from nonfractured reservoirs, were not applied to fractured reservoirs until the last decade or so. This was based on the belief that the injected fluid would bypass the oil through fractures, and not recover most of the oil, and that carbonate rocks are highly reactive at high temperatures. At the same time, the results of experimental, theoretical and pilot tests 2–15 , whichhave been appeared in the literature since early 80's, show the feasibility of heavy oil recovery from fractured reservoirs using steam injection. The process is complicated by nature. Interaction of heat transfer mechanisms-conduction and convection-with fluid flow in two different media is the reason for the complexity of the process. Multiphase fluid flow occurs under interaction of gravity, capillary. diffusive and viscous forces, with different degrees of importance in fracture network and in primary porosity. For example, recovery is enhanced from matrix block when capillary forces are stronger and imbibition is active, and the reverse is true when gravity drainage is active. In the fracture medium the role of capillary force is traditionally neglected. However, many studies show a large effect of fracture capillary on the behavior of double porosity systems 16–21 .

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 11–14, 1994

Paper Number: PETSOC-94-14

... we introduce skin and wellbore storage in the solution. Use of the technique is illustrated with the case of a horizontal well in a naturally

**fractured****reservoir**. Introduction Mathematical modelling of horizontal wells though abundant in the literature, seldom pay much attention to computational...
Abstract

Abstract Using the source function approach and the method of images, we have generated the pressure response of a horizontal well in a bounded homogeneous reservoir. Then we have convened the homogeneous solution to the case of a dual-porosity system by means of Laplace transform. Furthermore we introduce skin and wellbore storage in the solution. Use of the technique is illustrated with the case of a horizontal well in a naturally fractured reservoir. Introduction Mathematical modelling of horizontal wells though abundant in the literature, seldom pay much attention to computational efficiency. Only recently a couple of paper appear to deal with the situation. 1–2 .They use the method of images for early time and Fourier series for late time. Ohaeri and Vo 1 , using Laplace Transform, handle wellbore storage effects, skin and phase redistribution. Thompson et al, 2 on the other hand, deal with double porosity reservoirs, also through Laplace transform. They appear to be both faster than Daviau's approach 11 or Ozkan's approach 6 . Our main interests lie in naturally fractured reservoirs. Therefore we follow closely schemes of Thompson et al 2 , although Carvalho and Rosa 3–4 , present yet another way of generating pressure response of horizontal wells in aturally fractured reservoirs. Most of these solutions usesource functions, Fourier Series, Boundary Element Methods 4 or even Fourier Transform method 5 . Equations (Available in full paper) Thompson et al. 2 indicated that they were not successful in finding an approximate (polynomial) expression which reproduces the error function with sufficient accuracy. In the Appendix, we give two subroutines to calculate the error function. These subroutines give quite good graphical accuracy. The above formulation is efficient computationally. Theone thing to watch out for is the definition of the point of evaluation, (X D , Y D , Z D ) in space. Ozkan and Raghavan 6 give a very detailed discussion on this point. Since we are using a line source, and it is not possible to compute pressure drop on the source, one has to decide on a point away from the well-axis, to account for the radius of the actual well. Once we obtain P D from the above formulation we use a scheme given in Houze, Home and Ramey 7 to generate double porosity solutions. The approach involves the following steps: Find the Homogeneous Solution Laplace Transform Multiply by s Change s to s F (s) Divide by s Stehfest Inversion Double Porosity Solution where s is the Laplace parameter

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 11–14, 1994

Paper Number: PETSOC-94-65

... a variety of processes. In naturally

**fractured****reservoirs**, steam displaces the heavy oil present in the fracture network to create a steam zone which encompasses matrix blocks containing heavy oil. Heat conduction occurs from steam in the fractures to the heavy oil within the matrix blocks...
Abstract

Abstract Gravity flow plays an important role in thermal oil recovery under a variety of conditions. These include cyclic steam stimulation, conduction heating and formation heating in a fractured system. This paper addresses first the problem of steam heating of a naturally fractured reservoir in terms of a slab or a cylindrical block surrounded by steam. An analytical approach is used, which for the first time considers the transient temperature distribution within a single block. Heat integral method is used to obtain the unsteady-state temperature profile. The temperature distribution is used to calculate drainage rate under gravity flow. The solutions obtained are used to determine the effect of the principal variables involved in particular thermal diffusivity, time, and the geometric size. The application of our approach is extended to conduction heating problems under drag flow in which the heating boundary moves slowly. The criterion used to justify the stationary boundary assumption is Cited. Other potential applications include formation heating below an artificial fracture, and old cyclic steam stimulated reservoirs producing under gravity flow. Introduction Viscosity reduction is known to be the main contribution to higher flow rates in heavy oil recovery using steam 1 . Heating is achieved by either or both of two heat transfer mechanisms, namely conduction and convection. Field experience and modeling studies have shown that conduction lays the major role in a variety of processes. In naturally fractured reservoirs, steam displaces the heavy oil present in the fracture network to create a steam zone which encompasses matrix blocks containing heavy oil. Heat conduction occurs from steam in the fractures to the heavy oil within the matrix blocks. Conduction causes the mobilization of heavy oil in the vicinity of artificial fractures created by steam injection above parting pressure 2 . In mature steamdrives with complete override, gravity flow of heated oil by conduction as shown to be the major recovery mechanism 3 . In this paper, oil flow under conduction heating is modeled for three cases, and the extension of our method for some other cases s explained. Nolan et al. 4 proposed the applicability of steam injection for naturally fractured reservoirs. They solved the beat conduction problem for slabs, and found that temperature of single blocks surrounded by steam rises approximately to steam temperature within a year. Hence, they concluded that heat conduction was the only beating mechanism and performed numerical simulation to study oil recovery under this condition. Dreher et al. 5 performed numerical simulation and found that heat conduction plays the major role for heating matrix blocks once steam is injected into naturally fractured reservoirs. Saanan 6 analytically studied beat propagation in naturally fractured reservoirs containing impermeable blocks by considering unsteady-state heat conduction between matrix and fracture. His method was analogous to pressure distribution in double porosity systems. Van Wunnik and Wit 7 studied stearn injection into the gas cap of a densely fractured reservoir and investigated heat and fluid flow. They considered small matrix blocks and neglected temperature variation within individual blocks. In a companion paper 8 steam beating of a single block was studied by considering both conduction and convection terms in the heat equation.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 6–9, 1992

Paper Number: PETSOC-92-15

... Abstract This paper discusses important factors that influence the simulation of horizontal and deviated wells in

**fractured****reservoirs**. Although wellbore hydraulics affect the inflow along the well, they do not necessarily have an impact on the total well production. It is shown that it is the...
Abstract

Abstract This paper discusses important factors that influence the simulation of horizontal and deviated wells in fractured reservoirs. Although wellbore hydraulics affect the inflow along the well, they do not necessarily have an impact on the total well production. It is shown that it is the combined effect of wellbore hydraulics and relative location of injectors and producers that can significantly affect the production. For hydraulically fractured horizontal wells, it is shown that orthogonal fractures are more efficient than longitudinal fractures for very tight reservoirs. As the reservoir permeabilities increase, the effectiveness of orthogonal fractures lessen. Introduction The use of horizontal wells to improve recovery has been accelerating and this technology may turn out to be one of the most important aspects of oil recovery in recent and probably future years. The accurate simulation of horizontal well performance requires the coupling of the wellbore flow with the reservoir flow. For practical purposes, it is imperative that the solution of the wellbore flow should only be a small fraction of the run time. The direct solution of the momentum equation for wellbore flow is computationally intensive and is not appropriate for large field-scale simulation. Collins et al (1992) described a very efficient technique for modelling wellbore dynamics which is suitable for incorporation into reservoir simulators. In this technique, the wellbore flow equations were cast judiciously in a form similar to the reservoir flow equations. Thus, efficient techniques that were developed to solve the reservoir equations can readily be applied to solve the wellbore equations. Using this approach (referred to hereafter as "discretized wellbore" approach), Collins et al (1991a) examined the effect of horizontal wellbore hydraulics on simulation results. It was shown that the inclusion of wellbore hydraulics in the simulation yields an inflow profile along the wellbore substantially different from the case without wellbore hydraulics. This difference is more pronounced for higher-permeability reservoirs. Nevertheless, it was observed that the total well production appeared not to be affected by wellbore hydraulics. Subsequently, Collins et al (1991 b) examined the effect 01 wellbore hydraulics in heterogeneous reservoirs. They found that reservoir heterogeneities give rise to different wellbore pressure drops for different wellbore flow directions. However, they also reported that for the cases tested, the cumulative productions predicted with and without wellbore hydraulics were similar. This paper examines the effect of wellbore hydraulics in naturally fractured reservoirs. Naturally fractured reservoirs have high-permeability channels (i.e. the fractures) that act as conduits for fluid flow. The pressure drops in these fractures are very small and comparable to the pressure drop in the wellbore. The relative locations of injectors and producers are also considered. It is shown how these factors can significantly affect recovery predictions for horizontal and deviated wells. Several black-oil and compositional runs are used to study this effect. Hydraulic fracturing of horizontal wells has also received interest recently (Soliman et al, 1990; Dees et al, 1990). A discussion of the impact of wellbore / fracture orientation on the recovery is also given.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 6–9, 1992

Paper Number: PETSOC-92-21

... continuously for all 4 wellsthroughout the 40 months of production history. The conclusion is reached that conventional isochronal test analysis is notreliable to forecast deliverability References and illustrations at the end ofpaper of gas wells in naturally

**fractured****reservoirs**. Use of this approach...
Abstract

Abstract Isochronal, modified isochronal, and LIT testing are used routinely as a basisto forecast deliverability of gas reservoirs. This paper shows an applicationof this technique to the naturally fractured Palm Valley gas field in central Australia. Results are corroborated with the use of a dual-porosity numericalsimulator. The initial isochronal tests of 4 wells are presented together with thedeliverability equations. This is followed by a comparison with 40 months ofproduction history. The data show that values of "e" in the Rawlins and Schellhardt equation have been declining continuously for all 4 wellsthroughout the 40 months of production history. The conclusion is reached that conventional isochronal test analysis is notreliable to forecast deliverability References and illustrations at the end ofpaper of gas wells in naturally fractured reservoirs. Use of this approach caneasily lead to optimistic forecasts. Introduction The Palm valley Gas Field is situated in the central-northern Amadeus Basin, Northern Territory, Australia (Fig.1) approximately 120 km. southwest of Alice Springs. The structure is an arcuate anticline mapped from surface expressionand seismic data (Fig.2). The western and eastern plunges are poorly defined, however, the anticline axis can be traced for over 40 km. Production from the field commenced in August 1983 with the completion of an 8"pipeline to Alice springs. Natural gas has been used as a replacement forliquid fuels in electricity generation. Gas production from the field hasincreased steadily currently averaging 141,000 standard m 3 /d (5MMSCFD) to Alice Springs. In September 1986 a fourteen inch trunk pipeline was completed connecting thefield to the city of Darwin, 1300 km to the norch, and to several major townsen-route. Production for this pipeline has reached 622,000 standardm 3 /d (19 MMSCFD) and again has been used as a liquid fuelreplacement in electric power generation. Development of the field has followed the definition of reserves and during thepast 24 years, estimation of the gas reserves has been the subject of manystudies. The most significant being by Strobel et al. ' in 1976; areservoir simulation study by van poollen and Associates in 1985 and a recentreserves study by servipetrol Ltd. in 1990. These studies quantified reservesof 1.08 × 10 9 standard m 3 (3B.2 × 10 9 SCF),9.2 × 10 9 , m 3 (325 × 10 9 SCF), and 19.25 x10 9 m 3 (680 × 10 9 SCF), respectively andreflect the increasing contribution of production history and technologicaladvances. To July 1991, 1.20 × 10 9 standard m 3 (42.3 x10 9 SCF) has been produced from the field over its 24 year life andthis now provides valuable history for reserve studies. A recent paper by these authors 2 presented drawdown and buildupanalysis of the Palm Valley field using type curves for dual-porosity systems, 3 pressure derivatives, specialized semilogarithmic crossplots, anda numerical simulator for dual-porosity systems. The results of the analysiswere highly satisfactory. Another publication by these authors presented thenumerical simulation of Palm valley_ 4

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 6–9, 1992

Paper Number: PETSOC-92-76

... Abstract DECLINE-NFR is an inter-active computer process that allows type curve match evaluation of production decline curves in reservoirs with single and dual porosity behavior. DECLINE-NFR can also be used to evaluate hydraulically

**fractured****reservoirs**. Evaluation of constant pressure...
Abstract

Abstract DECLINE-NFR is an inter-active computer process that allows type curve match evaluation of production decline curves in reservoirs with single and dual porosity behavior. DECLINE-NFR can also be used to evaluate hydraulically fractured reservoirs. Evaluation of constant pressure production decline curves can lead to estimates of the following parameters: Transmissibility, drainage area and reserves in reservoirs with single porosity behavior. Skin can be estimated under certain conditions. Transmissibility, drainage area, reserves and fracture half length in reservoirs with single porosity behavior that have been hydraulically fractured. Transmissibility, natural porosity, average distance natural fractures, drainage and fracture between natural fractures, drainage and reserves. References and illustrations at the end of paper in reservoirs with dual porosity behavior. Transmissibility, natural fracture porosity, average distance between natural fractures, drainage area, reserves and fracture half length in reservoirs with dual porosity behavior that have been hydraulically fractured. Use of these type curves are illustrated with an example. Introduction DECLINE-NFR is a software package designed particularly to assist in the identification and quantification of naturally fractured reservoirs but it also operates at the same high level of performance in analyzing conventional and hydraulically fractured reservoirs. The purpose of DECLINE-NFR is to provide engineers with an easy to use production decline computer program. The program allows: transient type curve matching, and curve fitting of decline curves. DECLINE- NFR contains the following programs: MULTI-FIL is a pre-processor which reads production rates from a floppy disk or a file in the hard drive and generates an input data file for DECLINE-NFR. DECLINE-NFR is the main body of the package which analyses the production data. OUTPUT is a post-processor which generates a report of the output file from DECLINE-NFR. This package is also equipped with a printer and plotter support unit that allows an engineer to create presentation graphics on any Hewlett Packard or Epson compatible pr inter or plotter. Every aspect of the format of a plot can be saved in a file by our META option in the program and be plotted later. DECLINE-NFR is comprised of four different modules. Through the help of our forms system all input data required can be keyed in by hand through the keyboard. The four modules are: Input data editing module that creates an input data file in such a way that the file contains all the data required for interpreting the production history. Program control module that streamlines the overall operation to allow multiple analysis with the same data set. Type curve analysis module that performs various types of curve interpretation depending upon the type of reservoir analysis technique. Specialized analysis module that handles the non-linear fitting of Arps depletion curves. Everything an engineer needs is available at the touch of a button through the convenient form access system. This makes learning the program quick and easy. Production information stored in DECLINE-NFR files can be called to the screen in a few key strokes.