Midale Field Research Articles

Field-Scale Modeling of Interwell Tracer Flow Behavior to Characterize Complex Fracture Networks Based on the Embedded Discrete Fracture Model in a Naturally Fractured Reservoir

Summary In a naturally fractured reservoir, natural fractures can not only provide main paths for fluid flow and increase its permeability but also complicate flow behavior and production performance. Interwell tracer tests have been widely applied to estimate the petrophysical properties; however, limited attempts have been made to accurately identify the natural fracture networks. In this study, the newly proposed numerical models have been verified and used to characterize the fracture distributions in a naturally fractured reservoir conditioned to tracer transport behavior. The stochastic fracture modeling approach is implemented to generate the randomly distributed natural fractures which are dealt with the embedded discrete fracture model (EDFM) while ensuring its sufficient accuracy. To be specific, the matrix domain is discretized using the structured grids, within which each embedded fracture is divided into a series of segments. Subsequently, nonneighboring connections (NNCs) allow us to couple the flow of fluid and tracer between the nonneighboring grid cells, while the historical tracer profiles are matched to delineate the geometry and properties of the fractures by taking multiple tracer transport mechanisms into account. Furthermore, the influences of fracture number, fracture length, fracture orientation, and tracer dispersion on the tracer production concentration have been investigated through sensitivity analysis. The response of an interwell tracer model is sensitive to the fracture parameters rather than tracer properties. A fracture network with its orientation parallel to the mainstream direction will cause the earliest tracer breakthrough. The tracer breakthrough time with an average fracture length of 40 m is 110 days earlier than that with a mean fracture length value of 10 m, while the tracer production peak concentration for the former is nearly two times higher than for the latter. A larger fracture number results in an earlier tracer breakthrough, and an intermediate fracture number will lead to the highest tracer production concentration. Additionally, the newly developed model has been validated through its comparison with the commercial ECLIPSE simulator and then extended to field applications to identify the possible fracture distributions by simulating multiwell tracer tests in the Midale field. The flexible and pragmatic EDFM-based method developed in this study can model the interwell tracer flow behavior as well as characterize the properties and geometries of the natural fractures with better accuracy and calculation efficiency in comparison with other fracture simulation methods (e.g., local grid refinement method).

CO2-induced dissolution of low permeability carbonates. Part I: Characterization and experiments

The effect of elevated dissolved CO2 concentrations on compositionally and structurally distinct carbonate sample cores from the Weyburn–Midale CO2-enhanced oil recovery and storage site (Canada) was measured from analysis of 3-D sample characterization and fluid chemistry data from core-flood experiments. Experimental conditions (60°C; 24.8MPa confining pressure) and brine composition were chosen to mimic in situ reservoir conditions. Mineralogy and pore space distributions within the eight individual cores were characterized with X-ray computed microtomography and scanning electron microscopy both before and after exposure to brine with 0.5⩽pCO2⩽3MPa, while solution chemistry and differential fluid pressures were monitored during experiments.Our experimental study aimed to quantify the relationship between fluid flow, heterogeneity, and reaction specific to carbon storage at the Weyburn–Midale field by integrating characterization imaging, pressure data, and solution chemistry. Through the use of non-invasive microtomographic imaging, a variety of dissolution behaviors were observed, with variable effects on the evolution of solution chemistry and permeability as a result of heterogeneity within these two relatively low permeability carbonate samples. Similar-sized, evenly distributed pores, and steadily advancing dissolution fronts suggested that uniform flow velocities were maintained throughout the duration of the higher permeability “Marly” dolostone core experiments. The development of unstable dissolution fronts and fast pathways occurred in the “Vuggy” sample experiments when fluid velocities varied widely within the sample (as a result of increased pore structure heterogeneity). The overall effect of fast pathway development was to increase bulk permeability values by several orders of magnitude, allowing CO2-acidified fluids to travel through the cores largely unmodified by carbonate mineral reaction, as indicated by a lack of change in later-time solution pH levels at the core outlet. Given the impact of heterogeneity within low permeability cores, effort should be taken to incorporate smaller-scale heterogeneity into predictive models and such an averaging approach (utilizing the data and observations discussed here) is the topic of our companion manuscript (see Hao et al., 2013).Solution chemistry results indicated that steady-state carbonate mass transfer conditions were attained in the Marly dolostone experiments and during the earlier (pre-pressure breakthrough) portions of the Vuggy limestone experiments. Steady-state calcium and magnesium concentrations coincided with outlet solutions that were calculated to be at or very near to equilibrium with respect to both calcite and dolomite, relative to available thermodynamic data and considering experimental data scatter. Carbonate mass transfer data were evaluated against a variety of proposed carbonate dissolution mechanisms, including both pH- and pCO2-dependent expressions as well as a simplified pH-independent formulation. Based on this analysis, the calcite reaction rate coefficient was estimated to be ∼17 times faster than that for dolomite dissolution under our experimental conditions. This ratio is consistent with the use of rate equations that depend on carbonate mineral saturation without specifying additional dependence on solution pH or CO2 levels, and may be a result of the narrow experimental pH range. In addition, solution chemistry data were combined with time-dependent pressure data to constrain the exponent in a power-law expression describing the relationship between evolving porosity and permeability within the Vuggy limestones. This relationship as well as proposed carbonate kinetic expressions are further evaluated in our companion paper (see Hao et al., 2013).

Quantifying reactive chemistry along an injected CO2 flow path at the field scale using a Monte Carlo simulation approach

A Markov Chain Monte Carlo reactive transport modeling approach was applied to the problem of constraining the distribution of key reactive mineral phases along a flow path between a CO2 injector well and a monitor well at the Weyburn–Midale field in Saskatchewan. The methodology entails postulating a spatially correlated mineral distribution consisting of calcite, dolomite, anhydrite, and K-feldspar, characterized by specified volume fractions and intrinsic dissolution rates, in contact with an ambient brine composition along a one-dimensional flow path. Thousands of forward reactive transport simulations, conducted with PHREEQC, were run for the column, with simulated changes in brine chemistry compared with both synthetic test problem data as well as field data. We used a composite likelihood function to compare modeled and measured pH and concentrations of Ca2+, Mg2+, and Si. New realizations were proposed by replacing a small, contiguous section of the column with a new distribution of minerals that maintained spatial correlation with the remainder of the column. Proposed realizations were accepted/rejected using the Metropolis–Hastings acceptance criteria. If a proposal was accepted, the modified mineral distribution served as the basis for a new distribution, otherwise the modification was rejected as a non-improvement. Application of the inverse modeling approach to a synthetic problem demonstrated nearly complete recovery of a specified initial mineral distribution (i.e., “synthetic truth”) along the flow path, provided that “measurements” (synthetic data) were available across the entire column. Partial recovery of the synthetic truth was still achievable as the amount of data available for inversion was reduced to a single “measurement” collected at the column endpoint, mimicking the typical situation in the field. When applied to real brine chemistry data from a 1-km×1-km test area at the Weyburn–Midale reservoir, the inversion approach identified variations in the amounts of dolomite and calcite available for reaction along the flow path, given simplifying assumptions concerning permeability, pressure gradient, mineral specific surface, and the extent of mixing in the formation. These variations are qualitatively consistent with known compositional variability in mineralogy between the CO2 injector and the monitoring well location.

Field-Scale Modeling of Tracer Injection in Naturally Fractured Reservoirs Using the Random-Walk Particle-Tracking Simulation

Summary Modeling complex transport processes in naturally fractured reservoirs (NFRs) using classical continuum models may not be practically possible because the algorithms used in this type of modeling approach for the detailed structure of fracture/matrix systems require unreasonable computational time. Also, fractured reservoirs are highly irregular, and finite-difference calculations for such models often cause convergence problems. In addition, an exact representation of a complex fracture network in classical continuum modeling algorithms is highly difficult. An alternative is to use a nonclassical technique known as the random-walk particle-tracking (RWPT) algorithm. We showed earlier (Stalgorova and Babadagli 2012) that the random-walk (RW) technique can be adapted to model miscible flooding in a fractured porous medium at the laboratory scale. The unknown parameters used to match the model results were only the diffusion coefficients for oil and solvent, as the diffusive/dispersive transport (effective in fracture and matrix) was coupled with viscous (effective in fracture) and gravity (effective in fracture and matrix) displacement. Advantages of this method over classical simulation include a shorter computational time, which allows avoidance of simplifications; the ability to model the matrix/fracture diffusion process without any transfer function; and the representation of a complex and irregular fracture network system. In this paper, we modified this laboratory-scale RW model for field-scale applications. A series of tracer-test results from the Midale field in Canada was used to test the model. A fracture-network model was constructed on the basis of geological data, and then we used the RWPT model to calibrate the fracture network against tracer-test results. The results were compared to those obtained using continuum (dual-porosity) models, and it was observed that the connectivity and breakthrough times can be captured more correctly with the RWPT model. We performed a sensitivity analysis to identify the importance of different parameters for the simulation results. The new model and observations can be used to validate and calibrate stochastically generated fracture-network models and to estimate the enhanced-oil-recovery (EOR) performance of NFRs.

A decade of CO2 injection into depleting oil fields: Monitoring and research activities of the IEA GHG Weyburn-Midale CO2 Monitoring and Storage Project

Abstract Injection of CO 2 into the Weyburn Oil Field, Saskatchewan, Canada, began October 2000 and 10 years later approximately 18 MT of CO 2 will have been stored in the geological reservoir. The CO 2 injection is part of an ongoing enhanced oil recovery effort that will extend to 2035 and likely beyond. Both Weyburn and the adjacent Midale oil field are highly suitable for CO 2 -EOR and it is expected that, combined, more than 40 MT CO 2 will eventually be stored in these carbonate reservoirs. Currently about 2.4 MT and 0.4 MT CO 2 /year are being stored in the Weyburn and Midale fields, respectively, which now represent the largest site of monitored geological storage of CO 2 globally. The Weyburn Field is operated by Cenovus Energy and the Midale Field by Apache Canada. The anthropogenic CO 2 used at Weyburn-Midale is a by-product of coal gasification at the Great Plains Synfuels Plant in North Dakota, USA. The compressed CO 2 is delivered to the oil fields through a 323 km pipeline that crosses the international boundary. The IEA GHG Weyburn-Midale CO 2 Monitoring and Storage Project was established prior to the onset of CO 2 injection at Weyburn to assess monitoring methods and subsurface processes associated with the injection of CO 2 into geological storage sites. This research program is now in its second phase of research. Baseline 3D seismic surveys were performed over the Weyburn Field before injection and subsequent repeat 3D seismic surveys have been taken during the course of injection spanning multiple years and have indicated that CO 2 distribution within the reservoir can be imaged seismically. Similarly, repeat reservoir fluid sampling surveys have monitored a range of chemical and isotopic parameters to help identify processes associated with CO 2 -rock interaction. In addition, multiple soil gas and shallow hydrology surveys have been performed during the past 10 years with no indication of CO 2 reaching the surface. The current research program is building on many of the results obtained during the first phase of work on the Weyburn Field. For example, some of the current research includes applying stochastic methods to relate fluid chemistry to the seismic data to better characterize the distribution of CO 2 in the subsurface. Additional methods of modeling CO 2 distribution post-injection are also being demonstrated and integrated into several risk assessment methodologies. A detailed well database has been developed to catalogue characteristics associated with wells drilled at various stages of field development using different cementing practices and completion methods to assist with providing parameters for long-term modeling of well behaviour. In addition, a downhole well integrity testing program to examine cement sheath characteristics will be implemented in two wells in each of the fields. In summary, more than 30 research studies are being performed within this phase of the program to examine aspects of site characterization, well integrity, geochemical and geophysical monitoring methods and risk assessment. One of the goals for the work from this research program is to provide a best practices manual for the transition of CO 2 -EOR sites into storage sites. This paper provides an overview of the studies and results developing from the research program.

Fracture network modeling conditioned to pressure transient and tracer test dynamic data

We previously showed that the validation of fracture network models generated using discrete fracture network (DFN) approach through multi-well pressure transient data had certain limitations. In this paper, we tested other approaches used for modeling fracture networks: single porosity (SP) and dual porosity/permeability (DK), which are more common models for dynamic simulation than the DFN models. Multi-well pressure transient and tracer tests were used to validate the fracture network models generated as DFN and converted to grid based SP and DK models using static data. A sensitivity analysis was conducted to clarify the effects of fracture permeability, tracer dispersion, matrix–fracture interaction and other terms on tracer performance. Finally, a comparative analysis was performed to critically assess the reliability of different fracture network representations. The data obtained from the Midale field, Canada, was used in this exercise.Even though single or multi-well pressure transient tests are frequently used as an input for fracture network (or permeability map) generation and for the hydraulic calibration of discrete fracture network models, such tests provide limited information about the topology of fracture networks, i.e. connectivity and orientation. Tracer testing was suggested as a richer source of information about reservoir heterogeneity, especially in capturing fracture trends and orientation. The DK model was capable of satisfactorily modeling the pressure interference test in the validation process. However, it did not demonstrate the same accuracy for the tracer test simulation even though only the DK model was able to provide some meaningful match to the tracer tests. The major disagreement between the real and simulated tracer test response was the network connectivity. The limitations of this modeling approach were discussed in terms of representing the connectivity of the fracture network accurately.

Experimental Investigations on the Flow Dynamics and Abandonment Pressure for CO2 Sequestration and Oil Recovery in Artificially Fractured Cores

Abstract CO2 flooding in naturally fractured reservoirs is becoming increasingly more popular. The Midale Field is a good example of this phenomenon and has gained a great deal of interest, not only from enhanced oil recovery, but also from a CO2 sequestration point of view. To consider future opportunities for greenhouse sequestration in these types of reservoirs while improving oil recovery specifically in the Midale field, a series of experiments were performed. The goal of this work was to study the effect of miscibility (miscible, immiscible and near-miscible regions) and injection rate on incremental oil recovery and sequestration during continuous injection in fractured porous media. Another important aspect considered was to analyze the effect of pressure drawdown or depletion on additional recovery with sequestration optimization. First, artificially fractured Berea sandstone samples were used. CO2 was injected at constant, slow rates into the fracture, while maintaining the high-pressure into the core and the system. At the end of the production life, the pressure into the system was released to different pressure steps and kept for a longer period of time at each of the reduced steps of pressure. In between two pressure steps, the system was shut down for enough time to observe the effect of CO2 and oil diffusion/back diffusion. After a series of Berea sandstone experiments, a few tests were conducted on the Midale cores, which were obtained from a good quality matrix part of the field. Injection and production data were collected using a continuous data logging system, an analysis of the produced liquids and measuring the gas production using a continuous flowmeter, which led to the understanding of the mechanism. The results showed that the pressure blowdown, followed by shut in after continuous injection, can increase oil recovery significantly until a certain critical pressure. Storage capacity of the rock with change in pressure and amount of oil recovered during blowdown period will lead to the critical understanding of abandonment pressure during the project life to achieve the goal of sequestration and recovery optimization.

Integrated Modeling of the Fractured Carbonate Midale Field and Sensitivity Analysis Through Experimental Design

Summary We used an integrated solution by combining "direct" and "inverse" approaches to fracture network characterization in a stochastic numerical model. Static geological data obtained from cores and well logs were used together with dynamic data such as well-test responses to build 3D discrete fracture-network (DFN) models. We used the data obtained from the fractured carbonate Midale field in Canada. The fractured-reservoir model was constructed from static and dynamic (drawdown and pulse-interference tests) data. Matrix and several fracture parameters including fracture length, density/ spacing, aperture, connectivity, and orientation were evaluated in a quantitative sensitivity study to determine which characteristics have a higher influence on the accurate match to well-test response. We used experimental design to optimize the number of simulations needed for a sensitivity study and history match. The sensitivity analysis revealed a strong influence of matrix quality on the pressure response, suggesting that the history match can be specific to the simulated process and not necessarily unique. The results emphasize the contribution of matrix in the Midale reservoir and the need to simulate a broader range of processes for an accurate description of the fracture/matrix system dynamics. In a general sense, the approach used in this study proved to be useful in integrating fracture data from different sources and assessing its reliability and relative importance.

Characterization of Fracture Network System of the Midale Field

Abstract Enhanced oil recovery from challenging/complex fields requires extensive analysis of reservoir structure and good understanding of the effect of this structure on the dynamics of the process. Naturally fractured reservoirs are good examples of this kind and their fracture network characterization is still a bigchallenge. In this study, we analyzed the fracture network system of a portion of the Midale Field, a naturally fractured carbonate reservoir in the Williston Basin of southeastern Saskatchewan, Canada. Our study aims at an extensive characterization of fracture and fracture network properties and construction of a reliable fracture network model for further use in assessing the oil recovery by CO2 injection and CO2 sequestration potential. We integrated static data such as cores, logs and well tests to build 3D discrete fracture network models. Stochastic numerical approach was applied using a commercial software package. A fracture network constructed from static data was calibrated using well test data. Several parameters were evaluated in sensitivity studies to determine those characteristics of the network which have higher influence on the reservoir performance. Simulated well test response was checked against previously published well test data. This study allowed us to recognize uncertainties in critical parameters and propose some measures to manage those uncertainties. Introduction The Midale is a carbonate field located in southeastern Saskatchewan. Following the discovery in 1953, the field was developed on 32 ha spacing and proved to bear 81.9 ? 106 Sm3 reserves of 28.7 °API oil. The field belongs to the Mississippian oil trend located along the northern margin of Williston Basin. Subsequent to primary production up to 1962, the field was subjected to waterflooding on 83 inverted nine-spot patterns. To maintain the production which declined after 1964, an intensive program of vertical and horizontal infill drilling was undertaken. As of the end of 2006, approximately 1,000 wells exist in the field and more than 25% of OOIP was produced with an average watercut of 92%(1). The Midale Field is currently being subjected to tertiary recovery by miscible CO2 flooding. This field-scale CO2 injection was preceded by a 1.78 ha pilot project in 1984 ? 1989 which paved the way for a larger demonstration project. The CO2 Flood Demonstration Project encompassed 10% of the Midale Unit and paved the way for the field-scale application, which is expected to end up with an incremental recovery of 15% of OOIP(2). The Midale Field does not meet typical screening criteria for CO2 flooding. Nevertheless, extensive research and field applications proved that a proper design based on the analyses of the special combination of petrophysical, lithological and fracturing data can result in a successful carbon dioxide flood. The 24 m thick Midale Reservoir section consists of two main layers: dolomite-dominated "Marly" and vugular limestone, called "Vuggy". Both strata contain systematic fractures, though the degree of fracturing varies. Numerous studies conducted on the field revealed some characteristics of the natural fracture network (NFN) by both inverse methods, such as waterflood and carbon dioxide flood performance analyses, and well test analyses and direct methods such as core and log analyses.

Field-Scale Compositional Simulation of a CO2 Flood in the Fractured Midale Field

Abstract A stimulation test using electric heating was conducted on a single oil production well in the Schoonebeek reservoir in The Netherlands during 1989 and 1990. The performance of the test and its interpretation is described. The Bentheim reservoir sands are 31 m thick with a porosity of 0.3 and a permeability in the range 0.2 - 4 µm2; the oil has an in-situ viscosity at 160 mPa.s and is waxy with a cloud point very close to the reservoir temperature of 40 °C. The reservoir pressure of about 7000 kPa is supported by a strong edge aquifer. The objective of the test was to stimulate oil production with heat and, particularly, to melt wax that was suspected to be present either near the wellbore or uniformly throughout the reservoir. Prior to stimulation the oil production rate was 13 m3/d at a water cut of 35%. As the surface power dissipated was increased above 60 kW, the oil production rate increased abruptly to 30 m3/d with a bottomhole temperature in the range 54 to 60 °C; at higher power levels no further increase of production rate was observed. Analytical methods proved very useful for understanding the electric healing process, particularly for tracing the electric current flow path in the reservoir and for modelling the heat distribution and production response. Numerical simulations of the well's performance showed that the observed abrupt increase of oil production rate was compatible with the melting 01 wax at 60 °C and partial removal of a skin (of approximately 27) but not of a wax deposited uniformly throughout the reservoir. Introduction Though electrical heating has been used to stimulate well productivity al various times over the last 25 years, it is not widely applied. A lest of the stimulation method was recently completed on Well SCH-280 in the RW2-E area of the Schoonebeek oil reservoir of The Netherlands (see Figs. 1 and 2) by the Nederlandse Aardolle Maatschappij B. V. (NAM). In this paper we describe the properties of the Schoonebeek reservoirand the characteristics of Well SCH-280 and review the objectives, test programme and actual performance of the electric heating stimulation (EHS) test. In several respects, the information required to interpret the test unambiguously was not available. To circumvent these limitations, methods were developed for inferring the electric current flow path and heat distribution in the reservoir, Using both analytical and numerical simulation methods, a broadly consistent interpretation of the test was developed and this is described herein. FIELD PERFORMANCE OF OTHER ELECTRIC HEATING TESTS Over the last 25 years there have been a number of reports in the literature of planned or executed field tests of the electric heating process, mostly based on the ohmic dissipation of electric energy in the formation. Electrothermic Co., for example, stimulated four wells of the Little Tom field in South Texas. The reservoir there contains 8 - 12 °API gravity oil with a high pour point [1,2].

Streamline Technology for the Evaluation of Full-Field Compositional Processes: Midale—A Case Study

SummaryTraditionally, the evaluation of CO2-flooding processes is performed with finite-difference compositional-simulation models. However, compositional simulation is impractical for modeling large-scale CO2 floods because of computational run-time restrictions. In cases in which reservoir heterogeneity and fluid mobility dominate the reservoir recovery mechanism, streamline simulation offers a viable alternative to compositional simulation. The "reduced" physics in streamline simulation allows field-scale CO2-flood modeling to be feasible, as long as the streamline pressure/volume/ temperature (PVT) model can be calibrated so that the streamline model will produce accurate results for CO2-injection processes. Using streamline simulation allows for the evaluation of multiple full-field development scenarios that otherwise would not be possible with compositional simulation.The objective of the study was to provide CO2-flood performance forecasts under various full-field development scenarios for the Midale field. This paper focuses on the methodology and results from the 1,000-well, >400,000-gridblock, 45+-year streamline simulation of the Midale field. In particular, it discusses the construction and history match of the full-field model, the calibration of the streamline model with the compositional model, and the development of the full-field CO2 forecasts.

Pool characterization of Ordovician Midale field: Implication for Red River play in northern Williston basin, southeastern Saskatchewan, Canada

The Upper Ordovician Midale field is located in the northern Williston basin in southeast Saskatchewan, Canada. Hydrocarbons are hosted mainly in the dolomite reservoirs with burrowed textures in the upper Yeoman Formation. These reservoirs are characterized by intercrystalline porosity in the dolomitized matrix, with variable amounts of vugs and fractures, and can be divided into four zones. Reservoir zones 1 and 2, typically 6–10 m (20–33 ft) thick in total, are situated in the upper part of the traps and commonly bear oil. Although the underlying zones 3 and 4 are thicker, they commonly contain only water because they are located below the spillpoint of the hydrocarbon traps.The seismic reflection of the Red River reservoirs in the Midale field is characterized by a weak- to medium-amplitude trough immediately above the positive reflection of the Winnipeg shale. Where all four zones are present, an additional peak occurs on the seismic profile above the original reservoir reflection. This additional peak, however, disappears where reservoir zones 3 and 4 pinch out. Where there is an increase in the thickness of reservoir zones 1 and 2 or amalgamation of zone 1 with zone 2, the Red River reservoirs are characterized by high-amplitude and high-frequency reflections on seismic profiles.The Ordovician oil pools in the Midale area are associated with low-relief anticline structures. These low-relief structures are interpreted as the compactional drape of Red River strata over local Precambrian basement highs. The source of hydrocarbons in the Red River reservoirs is Ordovician kukersites. A wide range of API fractions for the oils from the Midale pools suggests a mixing of low-maturity oils, sourced from local kukersite beds, and high-maturity oils that migrated over a long distance from the south. The hydrocarbon production from Red River Midale pools is characterized by the fast rise of water cut and high water output, which can be attributed to the small pool size and the fracture systems connecting oil and water zones.

Pool characterization of Ordovician Midale field: Implication for Red River play in northern Williston basin, southeastern Saskatchewan, Canada

Pool characterization of Ordovician Midale field: Implication for Red River play in northern Williston basin, southeastern Saskatchewan, Canada

Stimulation of Horizontal Wells In Shell Canada Limited

Abstract The design and results of stimulation treatments in Shell Canada's horizontal wells to 1993 are discussed. Shell Canada's experience with horizontal wells started in 1988 with three wells drilled in the Midale Field, Saskatchewan. Application of horizontal technology grew and over 20 new horizontal wells or reentries were drilled in Shell's oil and gas fields during 1993. Horizontal drilling continued to be a major part of the subsurface capital program in subsequent years. The stimulation techniques used on the carbonate reservoirs of those horizontals varied dependent on well type, field characteristics and economics. The first horizontal well at Midale was cased, selectively perforated, and acidized. Most subsequent horizontal wells were, however, completed openhole. Shortcomings in the stimulation technology and efforts undertaken to improve stimulation results are discussed. Introduction Effective stimulation of horizontal wells presented some new challenges. The main challenges were:Identification of the hydrocarbon bearing and potentially productive intervals along the horizontal wellbore;Effective placement and diversion of acid to ensure the treatment of all productive intervals along the horizontal wellbore;Identification of the nature and magnitude of the damage to be removed. Shell Canada made extensive use of coiled tubing to stimulate its horizontal wells. This was due to coiled tubing's (CT) proven ability to be run to the end of the horizontal section and withdrawn while pumping/jetting acid and other treatment fluids across the zones of interest. Economides(1) had provided guidelines on acid treatment volumes per unit length of horizontal section, pump rates and withdrawal rates for CT to ensure effective treatment across the horizontal sections. Because of the difficulties experienced in removing damage from some horizontal wells using acids and the increased water production that was sometimes experienced, underbalanced drilling was identified as a means to minimize drilling damage(2). Underbalanced drilling was subsequently employed in Midale and Harmattan East. Whilst underbalanced drilling did provide benefits in certain settings, the incremental cost to drill underbalanced vs. effective stimulation later to remove damage was an important consideration. Stimulation of Midale Horizontal Wells Horizontal wells in the Midale oil field, located in SE Saskatchewan, presented unique challenges in stimulation design. This was due to the binary nature of the reservoir geology and to the maturity of the waterflood. The Midale formation from which hydrocarbons are produced is composed of a dolostone, commonly called the Marly, overlying a limestone, called the Vuggy. Imprinted on this geology is a fracture network trending southwest- northeast. Because of the higher porosity and more plastic nature of the dolostone, the Marly tends to be less fractured than the underlying Vuggy. While it might be anticipated that this fracture network would provide extensive communication between Marly and Vuggy, thin and laterally extensive barriers of tight limestone exist through out the field. The foregoing geologic factors greatly influenced the waterflood response of the Midale Unit. The field was developed on an 80-acre inverted 9-spot pattern, with a variety of infill wells for accelerated production.

Waterflood and CO2 Flood of the Fractured Midale Field (includes associated paper 22947 )

Summary The considerable remaining oil target in the naturally fractured Midale field prompted a major reservoir and recovery mechanism study in the mid-1980's. Included in the study were the detailed evaluation of 20+ years of waterflood history and the implementation and analysis of a tertiary miscible CO2-flood pilot. The study showed that tertiary miscible flooding should not necessarily be precluded for naturally fractured reservoirs. Introduction The 500-million-bbl Midale oil field is part of a trend of large Mississippian oil accumulations located in southeastern Saskatchewan along the northern margin of the Williston basin. The field was discovered in 1953 and developed on 80-acre spacing. In 1962, Midale was unitized for waterflooding, with eighty-three 320-acre inverted nine-spot patterns (Fig. 1). The reservoir section in Midale consists of a heavily fractured vuggy limestone overlain by a less fractured chalky dolomite. Waterflood performance is dominated by these oriented vertical fractures, which typically are spaced 1 to 4 ft apart. Production wells located "on-trend" from injectors(aligned with the fractures) showed sharp early response to waterflood. In contrast, response of "off-trend" producers was smooth and delayed. Oil produced to date represents recovery of 20% of the original oil in place(OOIP); ultimate waterflood recovery is predicted to be only 24% OOIP. The current water cut in the mature operation is about 80% (Fig. 2). Although the reservoir is fractured, well productivities are modest, with average production rates of 75 to 100 STB/D-well. Typical EOR screening criteria suggest that naturally fractured reservoirs are poor candidates for miscible CO2 flooding. Despite this rule of thumb, the favorable reservoir geology combined with the substantial EOR target at Midale persuaded the field owners to study implementation of CO2-flood technology. A 4.4-acre tertiary miscible CO2-flood pilot was conducted during 1984–89. Field-scale waterflood and pilot-scale CO2-flood results were history matched with a dual-porosity reservoir simulator. Field-scale CO2-flood recoveries are predicted to be an incremental 20% OOIP. The high CO2-flood recovery results from the favorable interaction of the different layers within the reservoir. The bulk of the large tertiary target is trapped in the chalky dolomites in the upper reservoir section. Although most of the CO2 is injected into the underlying heavily fractured limestones, gravity forces cause the CO2 to rise and come in contact with the oil in the dolomites. Based on pilot results and simulation studies, a $40-million commercial-scale CO2 flood began in Feb. 1992 in 10% of the unit. Geology The 4,600-ft-deep, gently dipping productive carbonates are overlain and underlain by impervious anhydrite beds.1The productive interval typically consists of a limestone (the Vuggy) overlain by a dolomite (the Marly), as shown in the type log in Fig. 3. The Marly zone has a layered geometry with good lateral continuity between wells. The Vuggy is less layered and more laterally discontinuous. The average gross thicknesses for the Vuggy and Marly zones are 40 and 30 ft, respectively; reservoir development is 20 ft in the Vuggy and 10 ft in the Marly. The reservoir is quite consistent in total thickness, varying from 60 to 80 ft across the majority of the unit. Internally, however, the Vuggy/Marly thickness ratio does vary considerably. The Vuggy zone contains two distinct rock types, intershoal and shoal. The intershoal Vuggy is present over the entire unit, while shoals have limited areal extent. Indeed, the majority of the unit is devoid of shoal Vuggy. However, where shoal Vuggy does exist, it dominates performance because of its high permeability. Intershoal Vuggy consists primarily of peloidal and bioclastic packstones containing mostly interparticle porosity. The shoal Vuggy consists of peloidal grainstones that display visually dramatic vugular and interparticle porosity. Despite these large pores, porosity values in the shoal and intershoal are very similar, ranging from 10% to 15%. Typical intershoal permeabilities are 1 to 10 md, with shoal permeabilities an order of magnitude higher. The Marly zone consists primarily of dolomitic wackestones and mudstones, with the mudstones forming the best reservoir rock. Porosity, which ranges from 20% to 35%, is predominantly intercrystalline with secondary amounts of pinpoint vuggy porosity. Marly permeability ranges from 1 to 10 md.

"A Multiple-Zone Acid Stimulation Treatment Of A Horizontal Well, Midale, Saskatchewan"

Abstract This paper describes an analysis of a multiple-zone acid stimulation treatment of a horizontal well in the naturally fractured Midale reservoir of southeastern Saskatchewan. Extensive characterization of the natural fractures with a wellbore imaging tool and core studie.s indicated that most of the natural fractures in the stimulated section were nearly perpendicular to the well trajectory and were spaced at 1.1 fractures per metre on average. A total of twenty seven, 4.5 m long, selected intervals of the open hole completed section were stimulated with retarded 15% HCI acid. Many of the pressure records also show classic fracture breakdown, propagation and shutin characteristics. The well had a modest productivity improvement after the treatment although most of the produced fluid was water. The reduction in the near wellbore skin is believed to be due to the opening and propagation of partially cemented natural fractures which were previously damaged with solid particulates from the drilling mud. This treatment demonstrates the potential for selective acid stimulation of horizontal wells completed openhole, provided that good zonal isolation is maintained. Introduction Despite the worldwide proliferation of horizontal wells in a variety of reservoir settings very little experience has been reported on the performance and comparison between different completion and stimulation methods. In particular, openhole completions which are a popular option for competent naturally fractured carbonate reservoirs, have not received much attention to date. Multiple hydraulic fracture stimulations of conventionally cased and cemented horizontal wells and matrix acid stimulation of openhole completions have been recently reported(1–3). It is the intention of this paper to describe a field case history of a multiple-zone acid stimulation treatment of a horizontal well and to highlight several important insights into the effectiveness of such stimulation techniques as derived from treatment pressure analysis. A complete and relatively unique dataset describing reservoir properties, in situ stress orientation and magnitudes, treatment pressures, and interpreted fracture diagnostics for the length of an acid stimulaled well is presented. Midale Field The Midale field is located in southeastern Saskatchewan along the northern margin of the Williston Basin as shown in Figure 1. The field was discovered in 1953 and since then has been extensively drilled with over 300 wells. The reservoir is at an average depth of 1400 m and contains nearly 82 million m3 of original oil-in-place (OOlP). The Midale field was unitized for waterflooding in 1962. Because of a recognized poor volumetric sweep efficiency attributed to high permeability anisotropy an infill drilling program was commenced in 1984. A miscible CO2 flood pilot project was also commenced in the same year. Details of the Shell Midale reservoir and its performance may be found in earlier publications by Beliveau(4–6). Based on several favourable reservoir attributes the naturally fractured Midale reservoir was considered a prime candidate for the application of horizontal wells. In 1989 three horizontal wells were drilled in the different parts of the field to tap into unswept portions of the reservoir and to evaluate geologica1 heterogeneity.

NATURAL SMOOTHNESS CONSTRAINTS IN CROSS‐HOLE SEISMIC TOMOGRAPHY1

AbstractTomographic inversion problems are ill‐posed and therefore solutions must be either damped or regularized to produce results that are geologically reasonable. We introduce a priori information in terms of parameter covariances to constrain the solution. We use slowness logs to determine the appropriate parameter covariances for the inversion of traveltime data collected for a cross‐hole geometry. We find that the logs exhibit power spectra proportional to a power α of the frequency. The value of α controls the smoothness of the inversion solution. For α < 0, the solution smoothness is maximized. Thus, knowing the correct value of α, which can be found from well logs, we can specify the appropriate amount of smoothing, rather than using some arbitrary level.Inversions were carried out on synthetic data for the case of α= 0 and α=−1. The use of α= 0 implies uncorrelated model parameters and is equivalent to standard damped least‐squares methods. We find that solutions for α= 0 show greater complexity than for α=−1 but this level of resolution can be illusory. An example from the Midale field, Saskatchewan, Canada, is inverted using both α= 0 and α=−2, given by the observed parameter covariances. The solution for α= 0 exhibits spurious detail which must be smoothed away. For α=−2, the solution smoothness is maximized and we recover only that structure which is required to fit the data.

The Prevention Of Resalinization The Reclamation Of Saltwater Spill Sites

Abstract After the initial treatment of a saltwater spill site has effected a reduction of soil salinity, a resalinization due to capillary rise ofsoil water can occur in certain circumstances. As an alternative to successive and costly chemical retreatments, prevention of resalinization by means of an organic trash covering of the spill site was investigated in a field study. The results suggest that such a cover prevents serious resalinization of the topsoil, in contrast to untreated sites, although the trend in sodicity is not as clear. Uneven coverage of the soil can to some extent be tolerated. Some implications for field treatment techniques are discussed. Introduction The initial effect of a saltwater spill on a mineral soil is to exchange calcium, magnesium and other ions for sodium ions, primarily on the surfaces of clays and organic matter(l,2). A subsequent freshwater flush of the soil may then cause the swelling of montmorillonite and dispersion and transport of kaolinite, among other effects, resulting in a permeability reduction. The physical chemistry governing this process is identical to that encountered in formation damage to freshwater sensitive reservoirs. A parameter commonly in use in soil science is the sodium adsorption ratio Equation (Available In Full Paper) with aqueous concentrations of ions expressed in millimole per litre (if milliequivalents per litre are used, the mean, rather than the sum of concentrations in the denominator, needs to be used). Impairment of permeability is to be expected if the S.A.R. exceeds 15(3), although sometimes problems are encountered at values greater than 8. The standard approach to reclamation is the addition of calcium salts such as calcium sulphate(l) or the more soluble calcium nitrate (2), preferably prior to the next rain or snowfall (Organic forest soils are an exception, and freshwater flushing is in most cases indicated(4).) The intent of the calcium amendment is to reverse the ion exchange process. In many cases, however, drainage in the spill area is poor, and the installation of a drainage system, with recovery and disposal of the sodium contaminated drain water, is not always a practical alternative. In such cases, therefore, reclamation programs rely on chemical amendment of the spill site soil, with attempts at early establishment of salt-tolerant vegetation, and the expectation of relatively slow drainage of the contaminating sodium salts. Some years ago, we reported the salinity reduction of the topsoil in a spill site by calcium nitrate amendment and irrigation(2). The site was identified as 9-16-6-11 W2M, in the Midale field (southeastern Saskatchewan) operated by Shell Canada Ltd. The soil electrical conductivity data prior to this treatment ranged from 29 000 - 56 000 microsiemens per centimetre (µS.cm− I)Treatment and leaching reduced this figure to 6900 µS.cm−I. However, by the following spring, it was found that the electrical conductivity had risen to 18 200 µS,cm− I, and the very dry following summer season did not permit a reduction to less than 11 000 µS.cm−l.

Pressure Transients Characterize Fractured Midale Unit

Summary The Midale Unit is a naturally fractured carbonate reservoir in the Williston basin of southeastern Saskatchewan. Recently, the Midale working-interest owners initiated a CO2-flood pilot project with several closely spaced wells. A comprehensive interwell pressure-transient test program was conducted for reservoir-characterization purposes before pilot program was conducted for reservoir-characterization purposes before pilot operations began. The combination of conventional, pulse, and interference tests resulted in a detailed local description of this naturally fractured reservoir. Selected pressure-transient data from the reservoir-characterization program are presented. The data dramatically illustrate the program are presented. The data dramatically illustrate the pressure-transient characteristics of an anisotropic, naturally fractured pressure-transient characteristics of an anisotropic, naturally fractured reservoir. Analytical techniques are reviewed briefly, and an interpretation technique for multiwell pressure-transient tests in wells with negative skins is included. A discussion of the pressure-transient behavior that is observed in wells with typical field spacing is also included. Introduction A significant proportion of the world's oil reserves exists in naturally fractured rocks. As a result, the pressure-transient behavior of naturally fractured reservoirs has been studied widely. These reservoirs, referred to as dual-porosity or dual-permeability systems, can be modeled with matrix blocks of various shapes separated by continuous fracture networks. Typically, the system permeability is largely associated with the fractures, while the tighter matrix contains most of the reservoir-storage volume and acts as a fluid source for the fracture network. Initial production from dual-porosity reservoirs is from the more permeable fracture network, which results permeable fracture network, which results in pressure decline in the fractures. Depletion of the fracture system causes pressure gradients to develop between the matrix blocks and the fractures, which results in fluid flow from the blocks into the fractures. This transitional flow period controls the reservoir-pressure behavior until the matrix fracture pressure regime equilibrates, after which the reservoir acts as a uniform system with composite properties. Pressure-transient testing is an important technique used to describe naturally fractured reservoirs. Each flow period (fractures, transitional, and composite) has distinctive pressure-transient characteristics. Pressure-transient behavior in real Pressure-transient behavior in real dual-porosity reservoirs, however, can be subtle and ambiguous, especially in normal situations with typical well spacing. For example, pressure transients controlled by depletion of the fracture network are rarely seen in the field because of the fast onset of the transitional flow period. Transitional- and composite-system pressure transients can be attributed to such other causes as layers, skin, faults, or boundaries. Wellbore storage can obscure key parts of the pressure-transient curve. For these and other pressure-transient curve. For these and other reasons, few comprehensive pressure-transient data bases exist for naturally fractured reservoirs. The scarcity of good data impedes refinement and validation of precise pressure-transient models. The Midale field (Fig. 1) produces oil from relatively tight, naturally fractured carbonates. The field was discovered in 1953 and produced competitively under primary depletion until unitization for waterflooding in 1962. Secondary performance is dominated fieldwide by the oriented-fracture system, which causes a permeability anisotropy of about 25:1. Recent implementation of a tertiary miscible CO2-flood pilot project in the Midale Unit, with 10 wells on 4.4 acres [1.8 ha], has allowed for very detailed reservoir characterization. Conditions in the Midale CO2-flood pilot are amenable to both single- and multiwell pressure-transient programs. An extensive, precise pressure programs. An extensive, precise pressure transient data base was acquired during pilot-testing operations. The reservoir pilot-testing operations. The reservoir model that was obtained from pressure-transient analyses is consistent with geological, petrophysical, and operational data, and it petrophysical, and operational data, and it provides significant refinement over earlier provides significant refinement over earlier reservoir models.

Midale CO2 Flood Pilot

Abstract The Midale oilfield is part of a Mississippian carbonate trend in southeastern Saskatchewan. The Midale Unit has been under waterflood since 1962, and is approaching an 80% water-cut. In an attempt to significantly increase recovery from this large resource base, Shell Canada Limited and partners have begun piloting a tertiary miscible CO2 process. This article focuses on the planning and design of the CO2 pilot, which began in 1984. The design integrates techniques from both observation and production-style pilots. The synergistic analysis of data from many sources is crucial for timely scale-up of results from the project, which will conclude in 1988. Introduction Oil was discovered in the Midale field in June 1953, by the drilling of Shell Midale A-7-18-6–10 W2M. Rapid development over the next five years resulted in the drilling of some 300 wells on 32-ha spacing. Production from the field was erratic during these early stages due to market and pipeline restrictions. It soon became apparent that primary depletion in the field would be due almost entirely to solution-gas drive. Analysis showed waterflooding to be the preferred secondary recovery method, so a pilot waterflood project was undertaken in 1960 in two field-scale patterns. Encouraging results from this pilot led to the formation of the Midale Unit, and a field-wide water flood on inverted nine-spot patterns commenced in December 1962. Oil production from the Unit peaked at 2300 m3/d in 1964, and declined steadily to 950 m3/d by 1985. Water-cut is approaching 80% in the mature operation. Average fluid injection and production rates in this low productivity reservoir are some 60 and 12 m3/d per well, respectively. A charge in investment climate in the early 1980s resulted in an explosion of activity for the Midale Unit, including the tertiary CO2 pilot and an aggressive infill drilling program. As well, upgrade of the existing waterflood facilities is under consideration. This surge in development activity lays the groundwork for continued Unit oil production well into the 21st century. Geology The Midale field(1) is located in southeastern Saskatchewan along the northern margin of the Williston Basin. The oil accumulation in the Midale Unit is in the Mississippian-aged Charles Formation. The Midale Beds pay section occurs as a basal member of the first (lowest) Charles cycle. The carbonate section of the Midale Beds is usually overlain by the Midale Evaporite of the Ratcliffe Beds and underlain by the Frobisher Evaporite. Classicall, the pay section has been divided into two major units, the upper Marly and lower Vuggy zones. The Marly is a microcrystalline dolomite with porosities in the 20% to 30% range, and net pay approximately 3.5 m out of a 6.5 m gross section. The underlying Vuggy is a micro- to coarsely crystalline fragmental limestone, with net pay of approximately 5.0 m out of a 10.0 m gross section and porosities of 10% to 15%. The non-pay in each zone is tighter carbonate rock. Both zones have initial water saturations in the net pay of approximately 40%, and matrix (air, unstressed) permeabilities in the 15 md range.