SPE 63286 Reservoir Characterization for Naturally Fractured Reservoirs Richard O. Baker and Frank Kuppe/Epic Consulting Services Ltd

Copyright 2000, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the 2000 SPE Annual Technical Conference and Exhibition held in Dallas, Texas, 1–4 October 2000. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract Reservoir characterization and simulation modeling of naturally fractured reservoirs (NFRs) presents unique challenges that differentiate it from conventional, single porosity continuum reservoirs. Not only do the intrinsic characteristics of the fractures, as well as the matrix, have to be characterized, but the interaction between matrix and fractures must also be modeled accurately. Three field case studies have been evaluated combining the “forward” modeling approach, typically used by geoscientists, with “inverse” techniques, usually incorporated by reservoir engineers. The forward approach examines various causes of natural fractures and its’ associated properties (e.g. fracture spacing, height, stress distribution, etc.) while the inverse approach focuses more on the effect created by the NFR (e.g. decline analysis, material balance, productivity, etc.).

constrained the development of NFR modeling1. This paper shows a number of integrated field studies, which have addressed the difficulties in characterizing NFRs, and presents a proven methodology to characterize and model them. Reservoir characterization presents a unique challenge in NFRs because of: 1) the need to characterize the fractures as well as the matrix 2) the need to characterize the matrix-fracture interaction. Characterization of the fracture includes defining parameters such as inter-fracture spacing, length, orientation, porosity, connectivity, aperture and permeability. As well, it is important to include realistic areal and vertical heterogeneity in both the matrix and the fracture systems. A fractured medium represents a highly heterogeneous system. Fluid transport and pressure dynamics cannot be fully replicated in a model using a homogeneous three-dimensional system. Recent work has emphasized the need to better characterize heterogeneities in matrix properties. The same attention, if not more, needs to be given to the characterization of fracture heterogeneities. Reservoir characterization is highly dependent upon the integration of skills from geologists, geophysicists, petrophysicists and reservoir engineers to an even greater extent in NFRs than in conventional reservoirs.

This study shows how a more powerful methodology is created, for the evaluation of naturally fractured reservoirs, when combining two techniques that have, historically, been applied in relative isolation.

The methodology presented ensures compatibility between the geological and engineering models. Specifically, this paper will show how NFR parameters were determined for the three fields in which this methodology has been applied.

Introduction

Geological (Forward) Approach

The development of reservoir modeling and reservoir characterization for Naturally Fractured Reservoirs (NFRs) has lagged behind simpler matrix flow dominated rock systems due to the practical difficulty in quantifying both matrix and fracture parameters. The complexities of, numerical and mathematical calculations have historically

On the geological side, there have been numerous attempts to compile fracture statistics on spacing, fracture height, orientation, aperture and length, and to subsequently scale these up to represent an effective fracture porosity and permeability. This is often referred to as the "forward approach" as it characterizes the reservoir from perspective of

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what caused or created the geological setting, as opposed to the effects (usually the Engineers' preoccupation) of NFR parameters. Fracture spacing, aperture, length and connectivity are functions of: a) porosity b) lithology c) structural position d) rock brittleness. One of the objectives of a fracture model is to generate empirical/analytical relationships incorporating fracture parameters and the above controlling factors. To do this, a certain amount of reservoir sampling is required to characterize the fractures. Unfortunately, lack of sampling or fracture characterization is a common problem in NFRs. Outcrops are a good source of data for fracture length and connectivity. Vertical wells have a low probability of intersecting vertical fractures. Cored horizontal wells, drilled perpendicular to fracture systems, also provide insight into inter-fracture spacing (or length). Thus, the relatively limited coverage from cored vertical wells is unlikely to yield a sufficiently large sample. For many of todays' developed fields, the data to correlate these variables is insufficient. Engineering data can sample large numbers of fractures (i.e., from the larger-scale pressure transient or production data) but this analysis cannot generate specific fracture parameters. Fracture parameters and empirical relationships must be derived from outcrop or field analogies. Despite the relatively small sample size, forward methods are critical because they often are zone or area specific. Although averages of fracture spacing and aperture are useful, as pointed out by Long2, there is ample field evidence suggesting that only a few fractures are hydraulically active and fluid flow may be dominated by extreme values of the fractured media. Outcrop studies can provide valuable information on fracture spacing, length, direction and connectivity. However, as Friedman et al3 demonstrated, weathering and stress effects may affect parameters in the outcrops, making them different from insitu conditions. The dimensions of matrix blocks are controlling factors for the recovery process. The inter-fracture spacing or determination of block volume distribution is therefore critical. Thus outcrop studies are important, despite the limitations.

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Tracer tests, historical production data and pressure transient tests provide us with the measurements, and the means, to generate inverse solutions for fracture lengths, fracture permeability and fracture connectivity. Engineering (Inverse) Approach On the engineering side, there have been attempts to understand the nature of the fracture systems using permeability and fracture storativity derived from well tests and production data. Unfortunately the production and pressure transient data, is typically characterized with generic “sugar cube" models and other simplifying assumptions. Often reservoir heterogeneity is transparent to these tests and analyses. Most buildup (pressure transient) tests and long term production testing is not zone specific and therefore have limited effectiveness for characterizing fracture heterogeneity. There is a large volume of engineering literature dedicated to solving the “dual porosity” pressure transient problem. In theory, the results from a pressure buildup test can be used to determine effective fracture spacing, however in 90% of naturally fractured reservoirs, pressure build up performance does not display dual porosity behavior4. Many NFR field examples in the literature show that a simple single porosity system can be used to obtain a reasonable match of pressure build up behavior5. The match is ultimately obtained with a higher effective permeability, when compared to matrix permeability. The importance of fracture heterogeneity has been neglected or minimized in engineering simulation studies. Without this heterogeneity, reservoir simulation models often underpredict watercuts (and water breakthrough time) and underestimate the amount of bypassed oil in the reservoir. In summary, both the geological approach and the engineering approach have limitations because of undersampling of insitu fracture systems and the use of theoretical models that use simplistic representations of real fracture systems, respectively. These approaches, independently, do not provide the means to accurately characterize the fracture system. This is a major problem in that long term deliverability and reserves are controlled by the effective reservoir permeability. Combining the forward and inverse approaches, however, allows us to narrow the range of uncertainty and build more realistic models of NFRs. Integrating Forward and Inverse Techniques

To increase the number of data control points and areal/vertical coverage, it is often necessary to use engineering or "inverse" techniques. An inverse technique is one where the dynamic response (i.e. the effect) of the larger scale system is measured and is then used to infer smaller scale characteristics.

It is critical to identify, early in the reservoir study: 1. what created the fracture system (i.e., regional, faulted or bended environment) 2. characteristics of the matrix-fracture system (i.e., fracture types, length, height, spacing etc.)

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RESERVOIR CHARACTERIZATION FOR NATURALLY FRACTURED RESERVOIRS

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matrix permeability and porosity the degree of communication between the matrix and fractures.

Alternative methods such as long term production decline data supplemented by pressure transient data, helps us to confirm large-scale transfer function parameters.

Determining how the fractures originated provides us with important clues for the areal and vertical distribution of fractures as well as a likely reservoir recovery mechanism. Table 1 shows how the features of the NFR system vary between the three different fracture systems and describes the associated production implications. As with most generalizations, there are exception to the "rules", indicated in Table 1.

Decline characteristics may provide important information on fracture volume, connectivity and permeability. The hydrocarbon volume present in the high permeability fractures will be produced rapidly. After this “flush oil” production the rate will decrease rapidly before stabilizing at a lower decline rate. Fracture spacing and the amount of communication between the fracture and the matrix, as well as the drive mechanism will control the stabilized rate.

The degree of flow between the matrix and fractures dictates which of many typical production problems may arise and also determines the level of recovery that may be expected. We've identified four varying degrees, or "types", of flow and their implications in Table 2.

Simulation Concerns. Depending, generally, on the contrast between matrix and fracture permeability and fracture spacing, the classical single continuum description may not be adequate for the simulation modeling of a fractured reservoir. For theoretical analysis and reservoir simulation, the irregular fracture distribution must be replaced by a regular matrix network (primary porosity) floating in the interconnected fractures (secondary porosity continuum). The idealized representation of fractures in the simulation model is shown in Figure 1.

3. 4.

The two primary parameters that control recovery in NFRs are 1) the magnitude and heterogeneity of fracture permeability and, 2) the extent of matrix-fracture communication. The fracture permeability will control well deliverability while fracture heterogeneity will control the extent of water/gas influx. Good matrix–fracture communication is essential for long–term productivity or high recovery factors. Matrix-to-fracture communication is dependent upon the interfracture spacing as well as the matrix permeability. These two parameters determine the strength of reservoir drive mechanism. If fracture spacing is small and/or matrix permeability is high, a very efficient waterflood (imbibition) and gravity drainage mechanism develops. Conversely low matrix permeability and/or wide fracture spacing often results in the bypassing of the matrix by injected fluids or aquifer influx and yields lower recoveries. The productive permeability cutoff employed controls the original hydrocarbon in place. From a mechanical perspective, the permeability provides a means of measuring the brittleness of the rock and thus fracture intensity. The matrix permeability therefore needs to be carefully considered in all NFR studies. The key to successful fracture characterization is to (a) focus on key variables that dominate the recovery process and (b) use techniques that combine the more accurate, "micro scale", tests (e.g. core analyses), with large scale tests (e.g. pressure buildups) that implicitly average the reservoir characteristics over large volumes of rock. Fracture-Matrix Interaction. Core analyses and logging tools such as the formation micro-scanner (FMS) provide an estimate of matrix permeability and fracture spacing. This provides us with sufficient data to at least estimate the “transfer function”, or the degree of matrix-fracture communication.

It is assumed, in the fracture continuum approach, that fractures are very long relative to the size of the blocks. As shown by outcrops, fracture length, especially in regional fractured reservoirs, can have limited length. Therefore, using the discontinuous fracture approach vs. a continuum approach in many NFRs may yield better results2. Figure 1 is an illustration of the classical dual porosity model. Both the fracture and matrix have non-zero porosity and permeability. Flow takes place within the fracture network and between the matrix and fractures. Each matrix block is assumed to be completely surrounded by fractures and cannot communicate directly with matrix adjacent blocks. This is not completely realistic because matrix blocks are "floating" while in reality the fractured media supports rock stresses and allow matrix blocks to touch. Most commercial simulators have the added feature of including matrix-matrix connections (i.e., dual permeability). Warren and Root (1963) presented an analytical solution of the pressure transient based on the dual porosity model of porous media. The key assumption was that the matrix to fracture flow is in pseudo-steady state conditions at all times (i.e., pressure declines uniformly throughout the matrix block). Fluid exchange between a matrix block and fracture would then be given by:

∂ (Φ m b ) = Φ m c m ∂Pm = − ∝ k m (Pf − Pm ) ∂t µ ∂t

(1)

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where Pm is the volume average pressure in a matrix block, Pf is the pressure in the fractures surrounding the matrix block; cm is the primary (matrix) compressibility given by;

c m = c r + c o (1 − S w ) + c w S w

(2)

and a is the "shape factor", dependent on the size and shape of the matrix block. The matrix blocks act as sources or sinks for the fracture system, according to equation 1, depending on the changes of pressure in the fracture system. Warren and Root obtained an analytical solution for single phase, radial flow in an infinite and finite reservoir, with constant well rate, as a function of the following dimensionless parameter, otherwise known as the transfer function:

λ=∝

k m rW 2 k eff

where: keff = k effx k effy rw = wellbore radius,

 1 1 1  ∝ = shape factor = 4 + + L 2  x

L y2

L z2  

Lx, Ly, Lz = fracture spacing in x,y and z direction, respectively This criteria for single porosity behaviour is usually supported by pressure transient analysis (i.e., no dual porosity behaviour observed). Engineers usually prefer, whenever possible to model a dual porosity reservoir with a single porosity model, capturing the effective permeability, because it halves the number of required gridblocks and shortens run time. Applying a single porosity model in a multi-phase enviroment may, however, generate erroneous results. The breakthrough time of the flood front, in a miscible flood or waterflood, is usually more rapid when "fingering" through fractures in the dual porosity model rather than the homogenized effective permeability of the single porosity model. Consequently the sustained higher production profile in the single porosity model would decline more rapidly in the dual porosity model. Care should therefore be taken to ensure the NFR characteristics not only satisfies single porosity, single phase criteria but that there are no multi-phase consequences when using a single porosity simulation model. Determining Fracture Parameters As mentioned previously, fracture permeability, fracture connectivity and fracture distribution, in water drives, waterfloods or gas cap drives, are critical controlling factors

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for oil recovery. The key parameter, governing connectivity between injectors and producers, is the fracture permeability2. Unfortunately porosity–permeability cross-plots, derived from core data rarely has any significance for NFRs as it merely represents the matrix properties. Also, conventional openhole logs are limited when predicting fracture distribution and fracture permeability. The key to successful fracture characterization is in developing empirical relationships that can relate fracture spacing to porosity, lithology, structure position, rock properties or layer thickness as shown in Figure 2. Initially, a theoretical geological fracture model should be conceived built on a combination of analog data, outcrop core and FMS/FMI data. The primary objective in these initial fracture models should be establishing the empirical relationship between fracture parameters and porosity, lithology, structure and rock brittleness. These initial conceptual geological fracture models usually have limitations in that fracture connectivity and individual fracture length are not yet well defined. Pressure buildup tests and production data can be used to determine effective permeability but are very sensitive to fracture length and heights as well as connectivity. Combining the analysis from the conceptual geological fracture models with the engineering data allows us to estimate these parameters. Production data and pressure data allows us to define fracture connectivity. Case Study 1 – The Weyburn Field The first case study shows how old log data and production data were integrated to successfully characterize the reservoir. This work helped increase field oil production rate by more than 50% using horizontal well technology. The Weyburn field is located approximately 130km southeast of Regina, Saskatchewan, Canada. The productive portion of the field covers some 180km2 and has produced medium gravity crude oil from the fractured, low permeability, Midale beds of the Mississippian Charles formation since its discovery in 1954,6 The Midale beds of the Mississippian Charles formation were deposited on a shallow carbonate shelf in the Williston basin. The reservoir is informally subdivided into the upper Marly and the lower Vuggy zone. The Marly is a chalky intertidal dolostone with occasional limey or limestone interbeds. The Vuggy zone is a heterogeneous, sub-tidal limestone. Although both zones are fractured, the Marly zone is less intensely fractured than the Vuggy zone. The porosity of the Marly ranges from 16% to 38%, averaging approximately 26%. Matrix permeability ranges from 1md too greater than 100md, with the average being less than 10md. There is some contribution to effective permeability from natural fractures within the Marly.

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RESERVOIR CHARACTERIZATION FOR NATURALLY FRACTURED RESERVOIRS

The Vuggy is a substantial limestone, which is more heterogeneous than the Marly due to the interaction of the depositional environment and diagenetic over-printing. Carbonate sands (packstones and grainstones) were deposited in the higher energy shoal regions and carbonate mudstones and wackestones in the quieter intershoal regions. Porosity and matrix permeability vary substantially, ranging from 3% to 18% and 500md, respectively. In addition, the Vuggy is extensively fractured. Highly permeable carbonate sand bodies and fractures control the magnitude and direction of the permeability anisotropy in the Vuggy. Injectivity studies also show that the majority of the floodwater is injected directly into this horizon. Waterflood development in Weyburn began in the early 1960’s. The waterflood has been very successful. Ultimate secondary recovery factors ranged from 25% – 35%, based on decline analysis. An extensive reservoir characterization study was required to provide reservoir simulation models for waterflood optimization, horizontal well evaluation and an assessment of miscible-flood potential. A strong regional fracture system controls the behavior of the Midale beds under waterflooda6. It was therefore, important to characterize and quantify fracture system parameters such as fracture spacing, aperture, rock type, reservoir quality and diagenesis. The characterization study incorporated reservoir performance (i.e., production and pressure) as well as geological and petrophysical data. Engineering data sources included injection profile logging, pressure transient and vertical pulse testing. Geologic data sources included both vertical and horizontal well core and wireline logs, repeat formation tester (RFT) and FMS logging. The neighboring Midale field producing from the same reservoir has been extensively studied7, 8,9 and served as a valuable source of information. Core and FMS observations indicate that the fractures are vertical to subvertical and are oriented approximately N45°E. Core observations clearly reveal that the forces causing fractures have been active on more than one occasion and have generated at least three ages of fractures. Some fractures are filled with anhydrite cement and are ineffective fluid conduits, whereas other fractures are very effective in moving fluids. Initial geological studies showed that there were significant differences in fracture intensity between the limestone and dolomite zones. As well, there were large differences in fracture intensity within limestone beds between shoal and intershoal areas. It is also interesting to note that fracture a

The Vuggy is most intensely fractured with fracture spacing of 1 ft in intershoal and 10 ft in shoal areas. The Marly has fracture spacing in the 3 ft to 10-ft range but is not fractured in some high porosity areas.

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intensity decreased dramatically as porosity increased. Old logs could therefore be used as semi-quantitative indicators of fracture intensity if the porosity and lithology could be estimated. The relationship between lithology and fracture intensity was very useful when creating the fracture model. Particular consideration was given to the more heterogeneous limestone layer (Vuggy), as it was important to capture its heterogeneity to accurately model primary flow conduits. Six simulation layers were selected to provide sufficient resolution for the Vuggy6. Previous simulation studies used one to two layers: which smears or over-averages porosity, lithology and the dominant high permeability layers. In matching injection breakthrough performance, it is critical to preserve the high permeability; high intensity fractures zones and not lump them together with lower permeability zones. Conversely, as indicated in early engineering studies, a shallow decline in production (5%-6% annual rate) was generated with long remaining reserve life. Watercut and breakthrough trends showed strong permeability anisotropy behavior. The watercut maps also showed a strong relationship between the geological shoal and intershoal areas and the anisotropic behavior. This relationship meant that it was important not only to look at dolomite/ limestone differences but to also look at the variations within the limestone (shoal versus intershoal). Studies identifying lithology and the geological environment therefore served as the cornerstone of the fracture characterization work. Estimates of fracture permeability had to be derived from the fracture spacing data (i.e., from core analyses) because of the limited number of good quality pressure transient tests. Fracture permeability is dictated by fracture aperture and spacing. After having combined calculated fracture parameters with the matrix parameters, the effective permeability could be compared with the insitu permeability determined form DST's. Note that DST's have a limited radius of investigation. To confirm calculated frac parameters a history match of the pressure drawdown was important. The pressure drawdown data was among the little data available to calibrate effective permeability. The magnitude of the anisotropic ratio (ontrend NE-SW to offtrend (NE-SE) was a critical variable in determining the effectiveness of the waterflood, horizontal wells and CO2 flooding. The anisotropy ratio in the simulation model was therefore pre-conditioned in the simulator using water breakthrough times at respective production wells. The project involved large potential oil reserves. Before simulation was initiated, six man-years of effort toward reservoir characterization had already been completed. The workflow diagram is shown in Figure 3. In our opinion, the

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key criteria to achieving successful characterization (i.e. one that generated an excellent history match) included:

1. 2.

1. 2. 3.

4. 5.

The ability to utilize open hole log response to estimate fracture spacing The use of horizontal well data to get significant fracture spacing statistics Using the ratio of water breakthrough times to precondition the permeability anisotropy ratio. This was subsequently altered slightly to achieve a history match in the Simulator Pressure Transient data was combined with direct fracture data to characterize the reservoir9 Selection of geological and simulation model grids that provided sufficient resolution for the intervals with large permeability contrasts.

In the first simulation run, 70% of all wells were matched in a 63 well model without any modification of the data6. Horizontal well watercut forecasts were within 3% of the actual values. Finally, it was found that the key parameters governing the waterflood and horizontal well recoveries, were vertical permeability and the distribution (and amount) of oil saturation. This study is a case where geological (direct) data and engineering (inverse) data was combined to get a better representation of the reservoir. Case Study 2: The Spraberry Field The Spraberry Trend in West Texas covers an area of more than 400,000 acres10. The Spraberry Trend was once deemed “The largest uneconomic field in the world,” with reservoirs that contained some 10 billion Bbls OOIP of which less than 10% has been recovered today. The Spraberry Trend Area produces nearly 60,000 bopd from more than 7,500 wells and has produced some 700 million barrels of oil11-16. The Spraberry Trend Area was first developed in the early 1950’s. The areal extent of the reservoir combined with many hundreds of wells having initial production rates of greater than 500 bopd, led some to believe the Spraberry Trend was one of the most prolific fields in the world. However, well productivity diminished rapidly as fracture depletion occurred. The first waterflood in Spraberry began in 1956. Generally, waterflooding in the Spraberry area has not been successful. Injected water bypassed the matrix and did not effectively sweep oil to producers10. Despite very similar fracture spacing between the Weyburn/Midale fields and the Spraberry field, there is a very large difference in waterflood recovery factors between these fields. The incremental waterflood recovery in Weyburn/Midale is on the order of 16% to 25%, whereas the incremental waterflood recovery is only 2% to 5% for most areas of Spraberry. Various hypotheses have been proposed to explain why waterflood recovery is so low, including:

3. 4. 5.

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Lack of pattern confinement and low injection well density Assumption that the primary direction of the fracture trend is N50ºE throughout the trend, thus leading to incorrect pattern alignment in some locations Low matrix permeability (Kair < 1 md), resulting in slow imbibition rates The reservoir rock may not be strongly water-wet, resulting in low capillary forces and slow imbibition rates Low reservoir pressures during the start up of waterflood, resulting in poor capture efficiency of oil as well as high initial gas saturations and low oil permeability in the matrix.

Preliminary studies show that perhaps all the listed explanations play some role in establishing ultimate recovery. The differences in waterflood performance between the Weyburn/Midale fields and the Spraberry field highlight the importance of not relying too heavily on analogous reservoirs to characterize the Spraberry NFR and that subtle differences in fracture/matrix parameters can have a huge impact on recovery factors, and the rate of recovery. A number of tests have been completed to characterize the Spraberry reservoir fracture system. These include horizontal core, pulse/interference tests, interwell tracer tests, buildup and falloff tests, FMI logging, outcrop studies, interwell tracer and mini-frac tests10. Like the Weyburn/Midale reservoirs, the direct approach (core/FMI) applications were very useful in identifying zone specific fracture trends, whereas pressure transient analysis was useful in identifying overall fracture permeability and connectivity. Interwell tracer testsb, core data and pressure transient analyses were used to identify fracture orientation. Pulse tests were conducted in the Midkiff Unit, of the Spraberry field in the 1960’s. These tests demonstrated that fracture permeability changed as the injection pressure and reservoir pressure increased18. The results suggest the effective fracture permeabilities are in the 30md to 200md range. Cross fractures (offtrend E-W fractures) also seemed to have been created from the high injection pressures. In this study, determining the extent of matrix-fracture communication was especially important in the evaluation of the CO2 flood efficiency. Since the degree of matrix-fracture communication is indicated by the waterflood imbibition process, this was more extensively studied. Laboratory imbibition experiments were designed to examine late stage decline rates on waterflood. This correspondence was then used to infer relationships between fracture spacing and matrix permeability.18 b

The interwell tracer tests in this area show very fast tracer breakthrough times (i.e., in the order of days).

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Successful reservoir characterization in Spraberry depended upon: 1. 2.

3.

Use of horizontal well cores to calibrate fracture spacing Re-examination of matrix properties and imbibition data that, coupled with field production data, promoted consistency between performance data and derived fracture/matrix properties. Use of pressure buildup tests, interference tests, production data (i.e. watercuts) and outcrop data to infer permeability anisotropy ratio.

Combining the direct with the inverse approach was critical. Quantifying the fracture spacing is important to the design of waterfloods and CO2 floods in a naturally fractured reservoir. The numerous studies completed have led to the generally accepted view that the fracture orientation in Spraberry is in a northeast to southwest trend. A more recent study examined fracturing in a horizontal well core. The study revealed a fracture set, located in the first layer, that was oriented N43° E while in a lower layer, there were two fracture sets oriented N32°E and N70°E. The average fracture spacing of the three sets were found to be 3.2ft, 1.6ft and 3.8ft, respectively. This confirms that more than one fracture direction can prevail and must be incorporated into the model. Case Study 3: The Waterton Field The Waterton field is located in the southwestern corner of Alberta at the front ranges of the Rocky Mountains and the foothills disturbed belt. The field consists of a westward dipping thrust sheet of Mississippian and Devonian carbonates with hydrocarbons trapped along the leading edge. The pool is extensively fractured, especially along the crest of the structure, and contains a near-critical, rich gas condensate with a compositional gradient19, 20. The Waterton field was discovered in 1959 and was put on production in 1962 upon the completion of the initial phase of gas plant construction. Twenty-four wells have been drilled in the "Sheet III" reservoir with the last well drilled in 1977. Drilling and seismic operations have been restricted to narrow valleys due to the rugged topography of the area.

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As with case studies one and two the key integation here was combining the openhole log (geological) data with mud loss and AOF test data (engineering inverse data) to characterize the fractures. In several key zones, solution enhanced fractures or karst development was proposed to account for these variations. This is consistent with observations made from pressure transient analyses from most of the wells. This study ultimately confirmed the presence of a complex heterogeneous fracture system with extensive karsting in several intervals. This was confirmed through the course of history matching as well as with pressure transient analysis. Conclusions 1) Forward and Inverse methods do not characterize the fracture network sufficiently, when used in isolation, because fracture connectivity is unknown. Combining these two techniques provides a more powerful complementary means of doing so. 2) Fracture heterogeneity is often over-simplified, or "smeared" in simulation models by using an insufficient number of layers or gridblocks (as was found to be the case in previous Weyburn studies). It is important to preserve the high permeability, high intensity fracture zones to accurately model breakthrough trends and ultimate recovery. 3) Accurate modeling of anisotropy, driven by overall fracture orientation, was critical in history matching, and predicting, waterflood movement, horizontal well performance and CO2 flood performance, in Weyburn. 4) Large scale tests (i.e., buildup and interference testing) and production data (i.e., water breakthrough and watercuts) were coupled with smaller scale evaluations (i.e., outcrops and horizontal well cores) to generate a consistent (i.e., good history match) and accurate model for predicting waterflood and CO2 flood recovery in Spraberry. 5) The "Inverse" techniques of the pressure transient analyses and matching production data (in reservoir simulator) confirmed the presence of karst development and the associated enhanced permeability, in the Waterton field. References

Data from well logs, cores, drilling and production records, pressure transient analyses and reservoir engineering analyses were used to characterize the variations in fracture and matrix properties in the reservoir, as shown in Figure 4. Conventional, tectonically induced fracture intensity was found to vary with lithology (dolomite versus limestone) and structural position. However, such “conventional” fracture descriptions did not account for the large drilling mud losses in some zones, variable productivities (not correlatable to structural position) and estimated volumes of initial hydrocarbon in place.

1.

2.

3.

Waldren, D. and Corrigan, A.F.: "An Engineering and Geological Review of the Problems Encountered in Simulating Naturally Fractured Reservoirs,” SPE paper 13717, 1985. Long J.C.: "Construction of Equivalent Discontinum Models for Fracture Hydro-Geology," Comprehensive Rock engineer Principles, Practices. Friedman, M. and McKiernan, D.E.: “Extrapolation of Fracture Data From Outcrops of the Austin Chalk I Texas to Corresponding Petroleum Reservoirs at Depth,” Petroleum Society of CIM paper 93-10-103, 1993.

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Fetkovich, M.J., Vienot, M.E., Bradley, M.D. and Kiesow, U.G.: “Decline Analysis Using Type Curves Case Histories,” SPE paper 13169, 1984. Carlson, M.R.: “Reservoir Characterization of Fractured Reservoirs in Western Canada,” paper 97-87 presented at 48th Annual Technical Meeting of the Petroleum Society of CIM, June 1997. Elsayed et.al.: "Multidisciplinary Reservoir Characterization and Simulation Study of the Weyburn Unit," SPE, Oct 1993. Beliveau, D., Payne, D.A. and Mundry, M.: “Waterflood and CO2 Flood of the Fractured Midale Field,” JPT, pp. 881-887, September 1993. Beliveau, D. and Payne, D.A.: "Analysis of a Tertiary CO2 Flood Pilot in Naturally Fractured Reservoirs," paper SPE 22947 presented at the 1991 SPE Annual Technical Conference and Exhibition, Dallas Oct 7-9. Beliveau, D.: "Pressure Transients Characterize Fractured Midale Unit," JPT (Dec 1989) 1354, Trans., AIME, 287. Schechter, D.S., McDonald, P., Sheffield, T. and Baker, R.: “Reservoir Characterization and CO2 Pilot Design in the Naturally Fractured Spraberry Trend Area,” SPE paper 35469, presented at the SPE Permian Basin Oil and Gas Recovery Conference, Midland, Texas, March 27 – 29, 1999 Barfield, E.C., Jordan, J.K. and Moore, W. D.: “An Analysis of Large-Scale Flooding in the Fractured Spraberry Trend Area Reservoir,” JPT, pp.15-19, April 1959. Brownscombe, E. R. and Dyes, A. B.: “Water-Imbibition Displacement - Can it Release Reluctant Spraberry Oil?” Oil and Gas Journal, pp. 99-101, November 1952. Elkins, L.F.: “Reservoir Performance and Well Spacing, Spraberry Trend Area Field of West Texas,” Petroleum Transactions of AIME, pp. 177-196,1953. Elkins, L.F. and Skov, A.M.: "Cyclic Water Flooding the Spraberry Utilizes "End Effects" to Increase Oil Production Rate," JPT, 1963. Elkins, L.F. and Skov, A.M.: “Determination of Fracture Orientation from Pressure Interference,” Petroleum Transactions of AIME, pp. 301-304, 1963. Howell, W. D., Armstrong, F.E. and Watkins, J.W.: “Radioactive Gas Tracer Survey Aids Waterflood Planning,” World Oil, February 1961. “Field Test Results of Surfactant Waterflooding and Balanced High Pressure Waterflooding in Spraberry Midkiff Unit,” Humble Oil Internal Memo, PRRC Spraberry Database, 1968. Baker, R.O. et.al.: " Characterization of the Dynamic Fracture Transport in an Naturally Fractured Reservoir," SPE 59690, March 2000. Aguilera, R.: “Advances in the Study of Naturally Fractured Reservoirs,” JCPT, p.5, May 1993. Nutakki, R. et.al.: "Three Dimensional simulation of a Fractured Rich Gas Condensate Reservoir: a study of Waterton Sheet lll. Thomas, M.B. et al.: "A New Interpretation of Fracture Distribution in Waterton Sheet lll: An Integrated Reservoir Characterization Study," SPE 35605, May 1996.

SPE 63286

Figure 1: Idealization of fracture reservoir according to the model of Warren and Root (1963).

Weyburn Field Objectives: Identify waterflood, horizontal well recovery potential as well as examine CO2 potential

Initial Geological Studies

Initial Engineering Studies

- Decline analysis -(showed long reserve life ) - strong permeability anisotropic behavior determined from watercuts and breakthrough timing

Fracture intensity is a function of: - Dolomite vs limestone - shoal vs. intershoal porosity

- highest permeability in NE to SW direction

W as initial geological model - compatible with engineering model - good overall continuity - relatively good waterflood - recovery (RF> 30%)

Key parameters identified for horizontal well evaluation waterflood

- vertical permeability - current oil saturation - distribution of oil saturation

Model Construction - determined fracture parameters from oil log data - used ratio (ontrend vs. offtrend)of water breakthrough times to give an initial estimate of permeability

anisotropy ratio

History Match

A history match was successfully achieved on the following critical parameters: - watercut - reservoir pressure - injection pressure - producing bottomhole pressure - saturation distribution at late stage of flood as flood as measured by vertical wells - RFT pressures buildup/DST derived permeability

Horizontal well projections, CO2 flood forecast

Figure 3: Workflow Diagram for Weyburn.

SPE 63286

RESERVOIR CHARACTERIZATION FOR NATURALLY FRACTURED RESERVOIRS

Figure 2: Data Flow for Characterization of Permeability for Natural Fractures and Reservoirs.

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RICHARD O. BAKER AND FRANK KUPPE

Seismic data

Pressure buildup and productivity index

Core/log/data Mud Losses Production/injection logging

Structural changes surface maps faulted areas

Zone specific data

SPE 63286

Total effective permeability

Allocation of fracture permeability on layer basis and areal basis

Figure 4: Workflow Diagram for Waterton.

NFR Parameters

Regional Fracture System

Faulted System

Bended System

Areal distribution

More uniform

Very localized faulted zones

Localized at crest and plunge areas Non-uniform higher frequency in thinners beds

Vertical distribution

Small vertical barriers often act to terminate fracture systems

Sensitivity of fracture spacing to lithology Sensitivity of fracture spacing to matrix porosity/permeability Fracture porosity

Very sensitive

Shales and lithology change do not terminate fracture set; very high vertical communication Not sensitive near fault

Very sensitive

Not sensitive

Sensitive

Very small φf < 0.1%

Recovery mechanisms (limiting factors)

Some of these reservoirs can be very successfully waterflooded (see Beliveau 1989)

Can be moderate; Depends upon karsting φf < 5 % Often wells water out; Water drive is common in faulted systems because of high vertical fracture continuity.

Can be moderate; depends upon karsting φf < 5% Often act like multi-layered reservoirs

Sensitive

Table 1: NFR System Parameters and Production/Recovery Implications.

SPE 63286

RESERVOIR CHARACTERIZATION FOR NATURALLY FRACTURED RESERVOIRS

Reservoir Type Type 1 Productivity essentially derived from fracture porosity and permeability alone

-

-

-

Type 2: Fractures provide essential reservoir permeability Hydrocarbons stored in matrix and fracture but fractures provides the means (i.e. permeability) to flow

-

-

-

Type 3: Productivity of a permeable matrix is enhanced with the additional fracture permeability

-

Type 4: Fractures do not contribute to porosity or permeability, but barriers act as flow.

-

Problems and Opportunities It is necessary to have high fracture intensity or high fracture porosity for an economic reservoir. May result in early water breakthrough the timing of which is governed by fracture height and vertical connectivity. Water influx is often accompanied by rapid oil decline. Fractures may generate production from otherwise unproductive rock. Determination of fracture porosity is critical in determining recovery. Primary and secondary recovery efficiency is highly dependent upon how well the matrix is exposed to the fracture network. Possible early water breakthrough and rapid oil decline. Development patterns must consider the reservoir heterogeneities (e.g. matrix-fracture communication may vary areally). Fracture intensity and dip must be known before pursuing development. Fractures improve productivity from poor deliverability reservoirs. Determination of fracture permeability and heterogeneity is critical in accessing effective parameters and recovery potential. There can be unusual responses in secondary recovery Drainage areas can often be elliptical It may be difficult to recognize or detect the fracture system Fractures may enhance already commercial opportunities Determination of fracture permeability and heterogeneity is critical (as for Type 2 reservoirs. Recovery is poor due to severe reservoir compartmentalization If properly planned, field development could be optimized Can have very poor secondary recovery because of compartmentalization

Table 2 – Reservoir Types (Adapted from Nelson).

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