This article focuses on interpretation of well test data from wells completed in naturally fractured reservoirs. Because of the presence of two distinct types of porous media, the assumption of homogeneous behavior is no longer valid in naturally fractured reservoirs. This article discusses two naturally fractured reservoir models, the physics governing fluid flow in these reservoirs and semilog and type curve analysis techniques for well tests in these reservoirs. Naturally fractured reservoirs are characterized by the presence of two distinct types of porous media: matrix and fracture. Because of the different fluid storage and conductivity characteristics of the matrix and fractures, these reservoirs often are called dual-porosity reservoirs.

The PDF file of this paper is in Russian.

Simulation of naturally fractured reservoirs is a challenging task. First of all, due to complexity of the geological structure and the structure of the pore space. Anisotropy of fluid flows and difficulty in assessing the recoverable reserves are results of the complex structure.

Naturally fractured reservoirs can be classified into five types according to capacitive and conductive properties of fracture network and porous matrix blocks.

Reservoirs, in which capacitive and conductive properties predominate in the fractured medium.

The first two types of reservoirs are modeled by dual-porosity model. The third and fourth types are modeled by dual-permeability model. And the fifth type can be represented by the single-porosity model with features, description of which is beyond the scope of this article.

In this paper, on the basis of literature review and personal experience description of dual-porosity/ dual-permeability models are given. The filtration equations of dual-porosity / dual-permeability model and the description of the mechanisms of flow between the pore medium and the fractured medium are presented.

The sensitivity analysis was carried out. It demonstrated that the effective permeability of the fractured medium depends on the absolute permeability of the pore medium in numerical simulation.

Abstract While the principles of enhanced oil recovery (EOR) are not new, field implementation has been scarce, particularly in the case of dual-porosity naturally fractured reservoirs, where the interaction of two different porous media creates a more complex displacement process. Several approaches to define the screening criteria on dual-porosity reservoirs have been postulated; the evaluation of the matrix-fracture interaction still requires complex models for proper EOR selection. This paper offers a multidimensional approach to EOR selection in dual-porosity naturally fractured reservoirs, starting with a detailed analysis of the matrix-fracture system and including: transmissivity/storativity ratios, fracture geometry, matrix block size, and dominant recovery mechanisms. Historical observations are used for characterization and identification of areas where one porous media is dominant and to help shortlist the desired EOR methods on an area-by-area basis. Two levels are considered in the analysis: the first level allows for a qualitative EOR ranking, suitable for reservoirs with limited information. The next level (numerically intensive) provides a quantitative EOR ranking with basic economics. The first-level ranking uses four different criteria for the selection—namely, pore-level displacement efficiency of the matrix-fracture system, EOR agent compatibility, matrix-fracture geometry, and the distribution of moveable hydrocarbons—and an internal advisor-system to achieve the ranking based on the fluid and reservoir properties. A combination of analytical and numerical models is systematically used to overcome the challenge of estimating pore-level displacement efficiency when the EOR agent contacts matrix and fracture systems simultaneously (including all the relevant recovery mechanisms, such as gravity drainage). An advisor system based on a global EOR project database, merged with in-house EOR engineering expertise, complements the EOR selection. Numerical modeling is used at a later stage to further substantiate and quantify the EOR solution, allowing for a full-cycle comparative evaluation. It is worth mentioning that the advisory EOR system presented here not only tackles a highly challenging topic but also provides “dynamic engineering guidance” throughout the EOR selection process. The authors believe that combining this reliable engineering process with ever-increasing computation power will help our industry to identify EOR potential easily.

Abstract Fluid losses during overbalanced well interventions particularly in depleted and under-pressured formations can become excessive in the presence of naturally occurring fractures, vugs, and caverns. Such features in combination with hydraulically induced fractures pose a set of issues that contribute heavily to the amount of fluid being lost into the formation. In this type of scenario it is not uncommon for the rate of fluid loss to exceed available pumping capabilities. This paper highlights the successful design and implementation of a robust pill to control excessive completion fluid losses, minimize formation damage in dual-porosity reservoirs with hydraulically induced fractures, while contributing to improve injection profile. This treatment contains a low-viscosity, solids-free, relative permeability modifier system coupled with biodegradable natural cellulose fibers for lost circulation control during workover and drilling operations. This system was applied to a cased-hole oil producer completed in the presence of natural and induced fractures (4500 psi, 15,500-ft TVD, and 270°F) in the Mirador, Barco, and Guadalupe formations in Colombia. This well was intended to be converted from a high-water cut producer into a gas injector to support field revitalization. Also, better access to the Barco and Guadalupe formations was desired to increase the injection profile. Excessive fluid losses during the workover made it impossible to carry out operations as planned. Ten pills of different conventional lost circulation materials (LCM) were implemented with no success. There was still a need to reduce losses below 10 bbl/hr to continue. Two 50-bbl pills of the proposed treatment were spotted to the target zone. Losses were immediately decreased to 9.1 bbl/hr on the first attempt, enabling continuation of the interventions with no further non-productive time (NPT). After completion, the well was successfully cleaned-out with nitrogen through coiled tubing (CT), and after two months, efficient gas injection was started as planned with the desired injection profile and no signs of further damage.

Abstract Using a breakthrough process, which does not require microbes to be injected, over one hundred Microbial Enhanced Oil Recovery (MEOR) applications have been conducted since 2007 in producing oil and water injection wells in the United States and Canada. On average, these applications increased oil production by 127% with an 89% success rate. This paper reviews the MEOR process, reviews the results of the first one hundred plus applications and shares what has been learned from this work. Observations and conclusions include the following: Screening reservoirs is critical to success. Identifying reservoirs where appropriate microbes are present and oil is movable is the key. MEOR can be applied to a wide range of oil gravities. MEOR has been successfully applied to reservoirs with oil gravity as high as 41° and as low as 16° API. When bacteria growth is appropriately controlled, reservoir plugging or formation damage is no longer a risk. Microbes reside in extreme conditions and can be manipulated to perform valuable in-situ "work." MEOR has been applied successfully at reservoir temperatures as high as 200°F and salinities as high as 140,000 ppm TDS. MEOR can be successfully applied in dual-porosity reservoirs. A side benefit of applying MEOR is that it can reduce reservoir souring. An oil response is not always seen when treating producing wells. The application of MEOR can be applied to many more reservoirs than originally thought with little downside risk. This review of more than a hundred MEOR applications expands the types of reservoirs where MEOR can be successfully applied. Low risk and economically attractive treatments can be accomplished when appropriate scientific analysis and laboratory screening is performed prior to treatments.

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 130370, "Application of Linear-Flow Analysis to Shale-Gas Wells - Field Cases," by Hasan A. Al-Ahmadi, SPE, Anas M. Almarzooq, SPE, and R.A. Wattenbarger, SPE, Texas A&M University, prepared for the 2010 SPE Unconventional Gas Conference, Pittsburgh, Pennsylvania, 23-25 February. The paper has not been peer reviewed.

Tight gas wells behave as if controlled by transient linear flow. The “half-slope” on a type curve indicates this behavior, which enables determining certain reservoir parameters. Linear-flow behavior has been observed in shale-gas wells also, but these wells tend to exhibit a significant “skin effect” that is less common in tight gas wells. This skin effect can mask early linear behavior but may be accounted for with a modified equation.

Introduction

Shale-gas reservoirs are being developed with horizontal wells and multistage fracturing. These wells produce in a transient-linear-flow manner, and, in some cases, this flow regime could last for years and might be the only flow regime available for analysis. A half-slope on the log-log graph of gas rate vs. time or a straight line on the square-root-of-time graph characterizes this behavior. Fig. 1 shows an example of a shale-gas well in transient linear flow for more than 2 years.

The approach used in this study was to assume that linear-transient-flow drainage out of matrix blocks controls production. However, unlike tight gas wells, shale-gas wells tend to exhibit a significant skin effect, which masks the early linear behavior and which must be accounted for with a modified equation. Gas adsorption is not accounted for in this model because most of the data are in the transient-flow regime in which gas-desorption effects are negligible.

Occurrence of Linear Flow

Fig. 1 shows a log-log graph and a square-root-of-time graph for daily production from Well 114. Transient linear flow is shown as a half-slope on the log-log graph and as a straight line on the square-root-of-time graph. However, the early part of these curves, before 200 days, does not seem to represent transient linear flow. In earlier work, it was thought that the early departures from a half-slope might represent bilinear flow in a dual-porosity reservoir. A more-plausible explanation and analysis were determined with this study.

Dual-Porosity Linear-Flow Model

An ideal shale-gas well would produce from a rectangular dual-porosity reservoir—a system of fractures with matrix blocks flowing into the fractures, with the reservoir not extending beyond the fracture system. Thus, this system is a linear dual-porosity system, and solutions have been presented as Laplace-domain solutions.

Two conceptual models are shown in Fig. 2. They are equivalent in the sense that they both represent dual-porosity linear systems. Model 1 is a linear, dual-porosity “transient-slab model.” The dominant fracture system in Model 1 is hydraulic fractures emanating from equally spaced perforation clusters in the wellbore. The matrix blocks in Model 1 are treated as homogeneous, although they may contain natural fractures. The main calculation advantage of Model 1 is knowledge of fracture spacing, L₁, because it depends on the perforation-cluster spacing.

Summary After-closure analysis (ACA) in homogeneous-matrix reservoirs provides a method for extracting critical reservoir information from pre-frac injection tests. This paper extends the theory and practice of ACA to identify the presence of productive natural fractures. Natural fractures are important to identify before conducting a stimulation treatment because their presence may require designs that differ from conventional matrix treatments. Literature shows that naturally fractured reservoirs are very susceptible to formation damage and require stimulation treatments to account for this issue. The historical problem, however, has been to confidently characterize the reservoirs pre-frac in terms of both the reservoir quality and the deliverability mechanism (fractures vs. matrix) before committing to these design specifications. This paper presents the results of a simulator used to analyze the mini-frac after-closure period to identify the presence of natural fractures. The simulation results are distilled into a field implementation methodology for determining the extent of natural fracturing and the formation reservoir quality. This methodology is also applied to a field case study to verify the practicality of the technique. Unlike previous mini-frac-analysis methods, this approach identifies natural fractures that are material to production and allows the engineer to distinguish them from "fissures" that are open only during injection and are not a production mechanism. Introduction Motivation for Identifying Natural Fractures. Identifying the presence of natural fractures is important for a broad range of reasons. On a field scale, realizing the presence of natural fractures can impact reserves estimation, initial well rates, production declines, and planned well locations. With respect to well completions, fractured reservoirs may necessitate a special stimulation approach. Because fractured reservoirs tend to produce from a relatively small reservoir volume (i.e., the fractures), these formations can be highly susceptible to damage (Cippolla et al. 1988). The literature shows that the use of foamed treatments (Cippolla et al. 1988), 100 mesh, and low gel loadings can be used to stimulate these reservoirs effectively. The literature also shows the disastrous results that can arise when damage-prevention steps are not taken (Cippolla et al. 1988). As a result, there is a definite need to identify natural fractures before a stimulation treatment so that the appropriate design decisions can be made. In the past, conventional well testing, such as pressure-buildup tests, has been used for determining the reservoir description. However, these techniques often prove costly both in terms of additional equipment requirements and delays in well on-line dates. In addition, conventional well testing may not be successful in low-permeability reservoirs because these wells may not flow at measurable rates before stimulation. These cost and reservoir limitations have forced the engineer to seek other low-cost methods for determining reservoir properties. One such option for acquiring these data is the use of a mini-frac injection test conducted before a stimulation treatment. The mini-frac analysis techniques available to provide estimates of the formation capacity (kh) and indications of the presence of natural fractures include preclosure and post-closure methods.

Abstract This paper presents dual-mesh computing in simulation of reservoir heterogeneities in single- and dual-porosity reservoirs. The dual-mesh approach provides a great tool for computing displacement processes and saturation distribution on the same fine-grid as the underlying geological models and is also extremely powerful in simulation of naturally fractured, dual-porosity reservoirs. This approach may even be used for the fine-scale computations in compositional modeling of petroleum reservoirs. In principle, the dual-mesh computing surpasses the benefits of streamline simulation both in single and dual-porosity problems. Several convincing examples are presented to illustrate the broad applications. The reasons for the accuracy and efficacy of the dual-meash computing are also explained. Introduction Reservoir heterogeneities, especially permeability anisotropy and flow channeling, are often prominent in many reservoirs commonly perceived as homogeneous. This is best illustrated in Fig. 1 for a field tracer test conducted in a confined inverted five-spot pattern in the M-1 micellar project in a sandstone reservoir. The tracer was injected into well E-5 during the waterflood operations. No tracer was detected in wells F-4 and F-5, even though these were two of the four wells surrounding injection well E-5. On the other hand, significant and lengthy tracer responses were observed in wells D-4 and D-6. Tracer response was even greater in well B-4 and significant in well D-2 outside the inverted five-spot pattern of injection well E-5. Gogarty highlighted these observations with the following statement: "These tracer results indicate the degree of heterogeneity that can exist in a reservoir. Application of an EOR process without understanding reservoir heterogeneity can lead to disastrous results." Carbonate reservoirs are also highly heterogeneous in flow properties. If these reservoirs have low permeability and are not adequately interconnected by fractures, then the ultimate oil recovery is very low with many pockets of undrained oil left behind. In fact, field experience has shown that infill drilling often leads to substantial increased recovery from the undrained portions of such fields. If the same reservoirs are interconnected by extensive natural fractures, then with proper utilization and monitoring of flow in fractures, one can take advantage of the capillary and gravity forces to improve the ultimate oil recovery substantially.

Abstract The flow of hydrocarbons in naturally fractured reservoirs is a very complex process involving the interaction of reservoir fluids with two distinct porous media. Accurate simulation of the physics of flow and fast execution of the resulting complex numerical code is fundamental in developing a viable tool for reservoir development and management. This paper addresses this issue by developing and evaluating a basic 3-D streamline reservoir simulator for counter-current water-oil flow in naturally fractured dual-porosity reservoirs. The concept is readily extended to counter-current gas-oil gravity drainage in such reservoirs. In the water-oil case, the counter-current flow of water and oil between the fracture and matrix media is generally attributed to water imbibition process. However, in oil-wet or mixed-wet rocks, the water imbibition could be non-existent, small, or strongly saturation-dependent. In these cases, given the right conditions, gravity potential can enhance oil drainage. These physical concepts are included in the simulator. In the gas-oil case, the capillary forces generally resist the gravity potential; thus, preventing counter-current flow of oil and gas. With proper placement of gas-oil contact in the fractures, the gravity potential can overcome the capillary resistance to invoke gas-oil gravity drainage. We will demonstrate how such a formulation can be included a dual-porosity streamline simulator. In the simulator, we apply an incompressible flow assumption to the fracture network in order to solve the 3-D water-oil displacement problem using a set of 1-D streamlines. Simple, but realistic, transfer functions, handle the matrix-fracture counter-current flow. These transfer functions depend on fracture-matrix relative permeability and capillary pressure functions, as well as the local gravity potential. A simpler, but perhaps more realistic, form of the transfer function is determined experimentally as a scaleable fractional oil recovery curve versus an appropriate dimensionless time. The transfer functions include other conventional reservoir properties such as permeability, porosity, and shape factor. The simulator was used to model several water-oil displacement test cases and the results were compared with Eclipse 100 dual-porosity model results. The comparisons were favorable and the differences in results were consistent with the difference in the simulation approach. We believe the streamline simulation of dual-porosity reservoirs could become an important tool for evaluating and managing fractured dual-porosity reservoirs. Because of the efficiency of the formulation, larger, more realistic geologic models can be modeled as compared to conventional simulators. For instance, simulating the frontal advance of the gas-oil contact in fractures, to invoke gravity drainage without gas breakthrough, can be accurately and efficiently handled using the formulation described here. Similarly, the breakthrough of water in fracture channels can be accurately simulated for very complex geologic models. Introduction Reservoir simulators based on the streamline principle offer an alternative to conventional finite-difference simulators. Low numerical dispersion combined with the ability to model a large number of cells with reasonable CPU time have made streamline-based simulators a useful tool for reservoir characterization and rapid evaluation of multiple reservoir development scenarios. Geological models are constructed with a high level of detail to ensure that the main geological features are included within the model. The result is a model that is composed of millions of cells. If several realizations are to be performed to obtain a realistic geostatistical distribution of reservoir properties, the final result is not only one but several multi-million cell models to be used in reservoir simulation. Dual-porosity reservoirs require the geological description of two pore systems, matrix and fractures. This means that the number of cells in the geological model doubles to accommodate the matrix and fractured media description.

Abstract The pressure transient behavior of hydraulically fractured wells has been the subject of considerable study over the recent years. Several investigators have presented solutions of the fundamental equations, identified qualitative diagnostic trends and suggested integral techniques. This paper presents a new method to solve the problem of analysis of well test data of the hydraulically fractured well. The new mathematical model for the vertically fractured well in the dual-porosity and homogeneous reservoirs was founded by using the elliptic flow model and the integral method of conservation mass. The solution for the new model was obtained in real space. The type curves for the vertically fractured well in both homogeneous and dual-porosity reservoirs with and without wellbore storage and skin effect were calculated. In order to consider the wellbore storage and skin effect, the techniques of Laplace numerical transformation and Laplace numeral inversion were used. The special results for homogeneous reservoir have been identified by compared with the results of other authors, such as the infinite conductivity solution of A.C. Gringarten, the finite conductivity solution of H. Cinco-ley and the finite conductivity solution of M.J. Economides which considered the wellbore storage. They all have the same identities. Two field examples are used to illustrate the use of the new method. The characteristics of the type curves for both homogeneous and dual-porosity reservoir are described. For the dual-porosity reservoir, the type curve presents seven flow periods: the wellbore storage controlled period, the skin effect controlled period, the bilinear flow period, the first transient period, the dual-porosity characteristic flow period, the second transient flow period, and the radial or pseudo-radial flow period. The solutions have the following advantages: The solution may be used for both homogenous and dual-porosity reservoirs, and for both infinite and finite conductivity vertical fracture. The range of the dimensionless conductivity is from 0.001 to 500. Even more, the type curve is quickly calculated by using this method than any others. The new sets of type curves can be directly used in the oil field. Introduction With the development of low-permeability reservoirs, hydraulic stimulation is more widely used in the oil field than before. However, it is more difficult to analyze and evaluate the test data from the vertically fractured well. P. 533