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This article focuses on interpretation of well test data from wells completed in naturally fractured reservoirs. Because of the presence of two distinct types of porous media, the assumption of homogeneous behavior is no longer valid in naturally fractured reservoirs. This article discusses two naturally fractured reservoir models, the physics governing fluid flow in these reservoirs and semilog and type curve analysis techniques for well tests in these reservoirs. Naturally fractured reservoirs are characterized by the presence of two distinct types of porous media: matrix and fracture. Because of the different fluid storage and conductivity characteristics of the matrix and fractures, these reservoirs often are called dual-porosity reservoirs.
Hammad, Muhammad (Pakistan Petroleum Limited) | Ahmad, Muneeb (Pakistan Petroleum Limited) | Siddiqi, Sarmad S. (Pakistan Petroleum Limited) | Siddiqui, Amir M. (Black Gold Oilfield Services) | Kuzyutin, Roman (TGT Oilfield Services)
Abstract One of the main challenges in a water drive gas reservoir is to track fluid movement as water breakthroughs occur frequently with depletion. The understanding becomes more challenging when the structure contains seismic/sub-seismic faults with the associated drive mechanism being edge water. Moreover, surveillance options are also limited for such reservoirs if they are producing through short string of a dual completion. Dual string completion is a cost-efficient technique as multiple reservoirs can be completed in a single wellbore. However, surveillance / logging cannot be performed across perforation intervals of upper reservoir due to operational concerns. As a result, the short string production can only be surveyed through the long string with the help of tools which have deep scanning radius extending beyond tubing and casing into the formation. One example of these advanced tools is Spectral Noise Logging (SNL) combined with High Precision Temperature (HPT) logging which have been used worldwide for such applications. This paper presents SNL-HPT results of two dual string wells completed in Eocene age carbonate reservoir. A total of nine wells are producing from the reservoir and the Gas water contact (GWC) was not encountered in any of the wells. Selected wells are located on either side of the structure with Well A producing 1.0 MMscfd gas and 1300 bbls/d water while Well B is producing 2.0 MMscfd gas and 800 bbls/d water. The reason of high water production from both wells was initially attributed to the presence of a high permeability streak in lower part of the reservoir and/or possibility of channeling behind casing. However, results of the SNL-HPT in both wells indicate signatures of fault or fracture flow. The major water production is coming from the middle and lower part of reservoir. Based on these results, the trajectory of one development well was optimized. The perforation interval of another well was also decided in accordance with the SNL-HPT findings, which resulted in water-free gas production. Quantification of reservoir flow profile in short string of dual completion well is possible through noise and temperature logging. This information would help in deciding appropriate workover strategy in existing wells and completion design of new development wells.
The process of scale inhibitor squeeze treatments is well known within the hydrocarbon extraction industry. These treatments have been applied for many decades to control inorganic scales in onshore/offshore production wells. This paper presents field results and laboratory evaluation data for the application of corrosion inhibitors via the squeeze process.
A series of coreflood tests were conducted with reservoir carbonate cores applying the treatment chemicals via matrix flow and also tests were conducted where the treatment chemicals were applied via fracture/matrix flow regime. Permeability measurements to field crude and synthetic brine were conducted prior to and following the corrosion inhibitor treatment package being applied.
Results from the coreflood studies showed that wettability alteration (increased water wetness) was observed within matrix flow only tests but in the fracture/matrix flow tests this damage was not observed. As the treatments in the example field were shallow penetration treatments it is clear that the fracture/matrix flow tests were reflecting the true application. The deeper penetration of chemical into the reservoir which was hoped would extend the squeeze life clearly shows formation damage so further work on the corrosion inhibitor formulation is required to reduce the wettability effects reported.
Corrosion inhibitors applied in the oilfield work by adsorption of the chemical onto metal surfaces to from a protective layer.1 The film is deposited via barrier coating between the environment and the pipe wall. 2,3 The barrier coating mitigates corrosion diffusion processes.
How are corrosion inhibitors applied?
Two methods of application are commonly available “batch” and “continuous”. In the batch process a high concentration of chemical is applied to the steel for an extended period of time to create a film4-7. In the continuous injection process small metered quantities of chemical are applied. It is more effective to link these two processes with batch treatment laying down a protective film that the continuous injection process maintains/repairs over time.
Abstract Scale inhibitor squeeze treatments in unfractured reservoirs can be readily simulated in matrix flow models, designing such treatments for application in fractured reservoirs is less routine. One reason for this is that the flow process and transport mechanisms by which the inhibitors are retained in fractured formations differ considerably from simple matrix flow. In previous papers, we described a diffusion-controlled transport model for scale inhibitors in low permeability fractured reservoirs where little matrix flow is expected. In this paper, the model has been used to simulate squeeze treatments performed on multiple wells in a fractured shale formation and compared to simulations using a matrix flow model. A number of squeeze treatments were performed on wells in a fractured shale formation yielding long treatment lifetimes. The squeeze treatments were designed using a matrix flow model. Calculations indicated the design pumping rate would require an injection pressure significantly more than the fracture pressure for the formation indicating little matrix may possible for this case. The treatments were successful, however, the observed field return did not match the prediction and in some cases longer treatment lifetimes were observed. When a standard matrix flow model was used, the resulting field isotherms were significantly different for each well in the formation. This is taken to indicate that the matrix flow model approach is not accurately mimicking the field data. When the same data was examined using the diffusion based fracture model, a single isotherm was found to be a good match for all of the wells from the formation. In addition, explicitly modelling the varying water production rates in the diffusion model gave good correlation with changing trends in the return concentrations seen in the field return. Furthermore the possibility of improving the treatment lifetime is considered, factors such as the effect of the overflush volume and injection rate are discussed as treatment modifications and the influence may have on formation damage. Accurate prediction of squeeze treatment lifetimes is important for scale management both economically to ensure optimum productivity and practically to schedule treatments appropriately. Until recently this has not been achievable for fractured formations without the use of full field simulators. The paper illustrates that an appropriate near wellbore model can give good agreement with field data and has been used to design better treatments without the need for complex full field simulators.
Abstract Water flooding is often applied to increase the recovery of oil from reservoirs. In practice, the water injectivity below the fracture propagation pressure (at so called matrix flow), is usually too low, so that the pressure is increased and the well is fractured. The fracture behavior is however different for unconsolidated sands than for consolidated rock as higher pressures relative to the minimum stress are required to obtain fracture propagation. Injecting water at higher pressure will lead to higher recovery. Our aim was to gain experimental and numerical data to establish the transition from matrix flow to fracturing. We present a series of model tests on different unconsolidated materials using large cylindrical samples with a diameter of 0.4 m. We changed the permeability of the sample and investigated the effect of cohesion by adding cement to some of the samples. It appeared that fractures obtained in material without any cohesion are really complex. On the other hand, adding some small cohesion to the sample, we observed a fracture more like “classical” fractures in competent rocks. For interpreting the tests, we have developed a fully coupled numerical model taking into account the two phase flow of oil and water, and the deformation of the sample.
Summary Pressure transient analyses using discrete fracture network models can provide insights to fracture length, stimulated reservoir volume, and fracture-matrix interaction. These questions are critical to understanding the production behaviors of unconventional reservoirs. This paper presents the results of Discrete Fracture Network (DFN) simulations usingfinite-conductivity fractures with constant spacing and size and more realistic fracture networks based on stimulated natural fracture networks. These are compared with production data from Eagle Ford wells that are deconvoluted to produce equivalent constant-rate pressure derivatives. Simulations of finite-conductivity hydraulic fractures with constant length and spacing produce distinct flow regimes. When the matrix has low permeability, the pressure derivative has half-slope, linear-flow periods corresponding to flow from the fractures and then the flow from the matrix blocks to the fractures. The transition between fracture and matrix flow has a steeper, near unit slope, which represents the depletion of the fracture before significant matrix flow occurs. When the matrix is relatively permeable, the effect of the matrix appears before the end of the fracture-only flow and the result is quarter-slope bilinear flow. Intermediate matrix permeabilities produce transitional behaviors between trilinear and bilinear flow. The transitions between fracture and matrix flow provide a basis for assessing fracture length, provided the matrix permeability is known; however, the transitions occur very early in production, within a day or much less time. A DFN model provides a more realistic simulation of production from the Eagle Ford shale in southwest Texas. The model uses fracture orientations and intensities from seismic and outcrop data. The fractures are assumed to be non-conductive prior to stimulation. The stimulated network model is calibrated to microseismic data. Unlike the simple simulations with constant matrix block sizes, realistic networks have a distribution of block sizes that produce derivative slopes between on half and one.. Production data from Eagle Ford wells were analyzed using pressure deconvolution methods to obtain equivalent constant-rate pressure derivatives. Late time derivatives show similar slopes to the complex DFN fracture simulations. The quality of the early-time deconvolution transformations of normal production data is not adequate for assessing fracture length due to primarily to low early-time data density. Understanding fracture geometries and behaviors may require several days of build-up data from wells that are shut in after production has started.
Abstract Cyclic steam stimulation (CSS) has been used in California since the 1960s. It has been used as an effective method for commercial oil recovery from the very low permeability diatomite formation since about the mid-1990's. Santa Maria Energy (SME) operates a CSS project in the Opal A diatomite of the Sisquoc formation on the Careaga Lease in the Orcutt Oil Field in Santa Barbara County, California. A 19-well CSS pilot has been operational since October, 2009. SME has received entitlement to proceed with an expansion consisting of 110 additional new wells. The CSS process designed by SME for the diatomite zone is one that works without fracturing the reservoir rock. An earlier paper was presented that describes techniques used for monitoring steam injection to help keep the injected steam confined to the zone of interest1. One such technique is Hall's method2 for water injection and adopted for steam. Corresponding algorithms have been programmed into a upervisory ontrol nd ata cquisition (SCADA) system to survey and analyze all steam injection cycles for all wells. The method has also been used to analyze steam injection step rate tests (SRT). This paper discusses: Two SRT's performed using steam injection; The analytical techniques used; and The results. Of special importance is that matrix flow is seen for CSS even though the injection bottom-hole pressure exceeds that which might normally be considered the rock fracture or parting pressure. This is due to partial plugging and other phenomena during steam injection that occurs to an extent not realized in more permeable rocks (such as very high permeability sandstones). These effects produce extra pressure drop during steam injection into the diatomite zone. This raises questions about the misuse of tubing wellhead pressure readings during steam injection as a reliable indicator of the reservoir formation parting pressure. As a result of this and other work, SME has adopted a specific range of CSS injection rates that are below a critical rate to help insure steam injection is confined to the zone of interest.
Baker, Richard (Baker Hughes RDS) | Stephenson, Tim (Gaffney Cline & Associate) | Lok, Crystal (Gaffney Cline & Associate) | Radovic, Predrag (Gaffney Cline & Associate) | Jobling, Robert (Gaffney Cline & Associate) | McBurney, Cameron (Gaffney Cline & Associate)
Abstract Over a thousand well pairs in five different fields in Western Canada have been examined using communication analysis techniques. The results of this analysis strongly suggest that in addition to conventional Darcy type flow through the matrix rock, there is also strong communication between wells through induced fractures, and/or natural fractures. Most of these five fields are not typically thought of as naturally fractured. Nonetheless this type of fracture flow exists. It is highly likely that these hot streaks are pressure sensitive and therefore have a geo-mechanical component that controls permeability. The geo-mechanical component means that permeability can vary with time and injection pressure. This work on the Western Canadian Sedimentary Basin (WCSB) is similar to work done by Heffer in the North Sea.
Abstract To predict correctly injectivity for Produced Water Re-Injection (PWRI), a good description of the formation damage by oil and solid particles have to be introduced in simulators for both fractured and non fractured flows. It is well known that the complex mechanisms of the formation of an external filter cake and of a deep internal damage should be better understood. In a previous published work 1 we attempted to quantify the petro-physical external filter cake properties. In this paper, results from core flood experiments (CFE) aimed to quantify the internal damage are presented. In recent published works, CFE were performed to examine, along rock samples, the deposition profile of only solid particles. The present work focuses on the oil droplets deposition profile. The mechanisms and laws governing the internal damage with oil are different from those concerning solid particles. Like solid particles, oil tends to deposit preferentially at the core entrance but quickly a moving front of oil droplet is generated. According to our experimental results a simple method for modeling the evolution of the internal damaged permeability is presented and finally an attempt is made to extrapolate these results to the well scale for both matrix and fractured flows. Introduction Models to reproduce injection injectivity of water solid suspension in wells are available 2,3,4. In these models, the physical formulation of internal damage is based on the classical deep bed filtration concept which needs to be calibrated with two parameters: The filtration coefficient ? and the formation damage coefficient ß. The filtration coefficient was extensively studied experimentally and a wide range of values of this parameter for a variety of solid particles was published 5. In our knowledge, no values of this parameter are available for oil and sSolid particle suspensions flow. The ß coefficient was for a long time difficult to determine experimentally for solid suspensions and from our knowledge no values of this coefficient are available in the literature for oily or oil and solid particle suspensions. A new method was recently proposed 6 to quantify parameters ? and ß from laboratory pressure measurements using the called 3 point pressure method. Other models 7,8 dedicated to simulate produced water re-injection under fracturing conditions, the depth of the internal damage is simply calculated from the injected volume of oil assuming an oil saturation and a fixed damaged permeability in the invaded zone. For other works 9 the concept of Barkman and Davidson is still used to simulate produced water injectivity decline. Towards this persevering difficulty to measure correctly the bed filtration coefficients especially when oil is involved, an alternative approach was chosen. It consists to quantify directly the permeability decline with an empirical law. Once the law is calibrated on core flood data, the law parameters are then extrapolated to the well scale. Empirical laws were already proposed for solid suspensions in the literature 10,11 which enables to correlate permeability decline with the fluid-rock system. Recently, an empirical law for internal formation damage was coupled 12 with reservoir flow and geo-mechanics to reproduce Pwri fractured well behavior. In the present paper a quite similar concept has been used just to compute the damaged reservoir permeability in matrix flow and then extended to fractured flow. The empirical law reproduces damaged permeability evolution for oil and solid particle emulsions. This law has the particularity to stabilize the permeability decline after a certain injection duration. Indeed, from the set of core flood experiments presented here after, oil, like solid particles, tends to deposit preferentially at the core entrance but far from the core entrance it generates a stabilized internal damage and permeability decline. This stabilization was also already observed in other works 13,14.
Abstract The Statfjord oil field, operated by Statoil in the North Sea, has been on production since 1979. The reservoir management strategy has been water flooding and secondary recovery mechanisms involving gas injection. To date over 63% of the STOOIP has been recovered. Good injector performance has been instrumental in the economic development of the Statfjord field. The purpose of this study is to investigate injectivity trends in the injection wells in order to understand the processes that influence initial and long term injectivity. This includes thermal fracturing of water injectors and a comparison of injectivity in Water-alternating-gas (WAG) wells during the various cycles of gas and water injection. The Statfjord production database contains large amounts of data for these wells including injection rates and pressures, injection profiles from production logging, and various static pressure measurements. Fracturing during water injection is found to result in folds of increase in injectivity of between 2 and 4. Whilst the resulting improvements in injection rates have been advantageous for pressure maintenance, out of zone fracturing in some wells has been detrimental to the efficient sweeping of some sand members. Gas injection on Statfjord is shown to be governed by matrix flow and fractures from previous water injection cycles do not stay open during subsequent gas injection in the WAG wells. Introduction The Statfjord Field was discovered in 1973, declared commercial in August 1974, and started production in 1979. The field is over 25 km long and averages 4 km in width, making it the largest producing oil field in Europe. Statfjord is located in the Tampen Spur area, in the northern portion of the Viking Graben and straddles the border between the Norwegian and UK sectors. The field is developed by three fully integrated Condeep concrete platforms. All three platforms have tie-ins, as shown in Fig. 1. Production is from the Brent, Dunlin and Statfjord reservoirs, with the main reserves in the Brent and Statfjord reservoirs. As of December 2003 the cumulative oil production is 626 million Sm. This represents 63% of the initial oil in place. The field has a total of about 90 active production slots and 30 injection slots. At the time of writing oil production is about 24,000 Sm /d and the average water cut on the A, B and C platforms is 86%, 80% and 80% respectively (not including third party volumes). Water injection totals 140,000 Sm/d of which 8% is PWRI. With the current drainage strategy, the expected recovery factor at abandonment is 66%. Reservoir development has centered around pressure maintenance above bubble point. Historically, this has been achieved through water flooding from down dip seawater injectors in the Brent formations and crestal gas injection in the Statfjord formations. More recently WAG and up-dip water injection has supplemented these secondary recovery mechanisms in an effort to improve macroscopic and microscopic sweep. The current reservoir pressure is 320–340 bar at datum 2469 m TVD MSL. Maintaining reservoir voidage will enable the majority of wells to produce naturally to the inlet manifold with water cuts up to almost 100%. Wells completed in areas with poor pressure support are routed to low-pressure manifolds. Feed for the water injection system is from the seawater lift system. Water is taken from the sea at a depth of 65 meters below sea level and filtered through coarse 80-micron filters before being deoxygenated. Biocide and oxygen scavenger are then injected into the system downstream the deaerator. In the last year or so biocide has been replaced by injection of nitrate on two of the three platforms in order to reduce corrosion and reservoir souring. The seawater in this part of the North Sea contains very low concentrations of inorganic particulate (<1 mg/l) and the organic particulate concentration varies seasonally. The coarse filters are primarily designed to prevent blinding of pump screens during plankton bloom periods. Scale inhibitor is added to the injection water at wellhead only during the first period of injection (first few weeks) for new wells in order to prevent possible sulphate scaling in the near formation on initial mixing of seawater with formation water.