bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effect of Natural-Fracture Density on Production Variability of Individual Wells in the Nikanassin Tight Gas Formation
Authors: Gonzalez Laureano , Aguilera Roberto 
Published: June 2014

Summary
A statistical model with a strong correlation has been developed to determine average fracture density (FD) on the basis of production variability of 271 individual wells producing exclusively from the Nikanassin and equivalent formations in a large area of more than 15 000 km2 in the western Canada sedimentary basin (WCSB) in Alberta and British Columbia. Fractional production-variability plots (FPVPs) published by Nelson (2001) have been used successfully in the past in many naturally fractured reservoirs around the world. Up to now, the generation of such graphs has been based on empirical observations from field-production data. The variability of the graphs is interpreted qualitatively as a measure of reservoir heterogeneities. This paper presents a sequential methodology to reproduce empirical fractional variability plots of the Nikanassin tight gas formation using real data, an empirical variability-distribution model (VDM), and dual-porosity numerical simulation. Different simulation approaches and multiple sensitivities were generated from the simplest to the most-detailed cases to understand what causes the curvature of the FPVP in Nikanassin wells. The base simulation case is a homogeneous dual-porosity model, where porosity and permeability are set constant for matrix and fractures. A second case accounts for a heterogeneous dual-porosity model generated through statistical distributions of porosity and permeability. Finally, discrete-fracture-network (DFN) methodology is used to generate multiple fracture models from which stochastic fracture properties are generated for the simulation model. It is concluded that curvature of the variability plot is affected mainly by the occurrence of natural-fracture density. This finding permits estimating FD approximately parallel to the northwest/southeast-trending thrust belt of the Canadian Rocky Mountains in both the west and the east side of the deformation wedge. An unexpected result is that for a significant change in fracture permeability and porosity with constant FD, the fractional production-variability curve is not affected significantly in the case of gas reservoirs. Although the method is applied specifically to the Nikanassin tight gas formation, the theory is developed in detail in such a way that the methodology can be applied in other tight gas reservoirs around the world. Findings from this work are in good agreement with the geological description of the Nikanassin formation and with a production analysis performed in six Nikanassin study areas based on the cumulative number of wells vs. yearly cumulative gas production.
Effective Caprock Determination for SAGD Projects
Authors: Collins Patrick M. , Walters Dale A. , Perkins Thomas W. , Kuhach Joseph D. , Veith Edwin J. 
Published: June 2014

Summary
In the oilsands of western Canada, caprock integrity has become a central issue in projects using steam-injection-recovery processes such as steam-assisted gravity drainage (SAGD). Caprocks contain steam and fluids within the reservoir; therefore, understanding the integrity of the caprock over the life of the operation is critical in order to ensure a safe and economically viable project. A multidisciplinary study was undertaken to evaluate geological facies as potential caprock for Ivanhoe Energy's Tamarack project. This examination of the historical performance of operating SAGD projects correlated the maximum vertical growth of the steam chamber with geology and the steam-injection operating pressure. The study found that SAGD steam chambers are being constrained by geological facies grading upward to poorer reservoir quality, rather than being constrained by shallower, regionally extensive, massive, low-permeability barriers. Geomechanical reservoir simulations of Ivanhoe Energy's proposed Tamarack SAGD project predict that the steam chamber will be constrained similarly as reservoir quality degrades upward. The simulations show the pressure and stress gradients in the formations above the steam chamber as a function of time and operating conditions, allowing for a more accurate assessment of steam containment and the risk for shear and/or tensile failure. The findings are significant because they confirm that the vertical growth of SAGD steam chambers has been halted, in effect, by facies consisting of interbedded sands and mudstones. These effective caprock facies have higher fracture pressures than the regionally extensive low-permeability barriers because these facies are found at greater depths. The higher fracture pressure justifies a higher maximum operating pressure, with its associated higher reservoir temperatures resulting in much lower bitumen viscosities. As a result, SAGD well productivity and project economics are greatly improved, particularly for shallow SAGD projects.
SAGD-Pair Performance Optimization: A Field Case Study of Recovery Enhancement
Authors: Jorshari Kamran , O&apos;Hara Brendan , Jones Ramsey 
Published: June 2014

Summary
Performance of fields under thermal recovery processes has been improved considerably by experimenting with new techniques and innovative operational solutions in heavy-oil and extra heavy oil fields (Butler 1994; Singhal et al. 1998). By far, steam-assisted-gravity-drainage (SAGD) and cyclic-steam-stimulation (CSS) methods have been the most compelling and have shown a successful history in these oil fields (Butler et al. 2000; Butler 2001). At the Celtic heavy-oil field, Husky Energy experienced three phases of optimization over the course of 10 years of recovery. The Celtic field consists of 28 SAGD pairs located in the Lloydminster heavy-oil region that have been in service since 2001. Among these pairs, there are three SAGD pairs (F Pad East) with early productivity challenges in addition to downtime caused by sand production. Following new geological realization and reservoir studies, the injector wells were converted to production wells performing a horizontal CSS process. In 2008, and in an effort to maintain production, a detailed numerical-simulation study was conducted to compare different steam support configurations and the result was justified for field execution. The outcome resulted in four directional steam-injection wells (G Pad) permanently started to support the current horizontal producers. In 2009, the new configuration commenced and is still in operation today. Communication with horizontal wells has been confirmed on one side of the pattern, and it has been extending gradually to the other side as it was investigated in other work (Edmunds 1991; Al-Salhi et al. 1997). Recently, acquired field data suggest that the process is exceeding the expected oil profile and its steam consumption is less than anticipated. The geological review, history of the F Pad East pairs, results of numerical-simulation study, and recommendations are presented in this paper.
A New SAGD-Well-Pair Placement: A Field Case Review
Authors: Jorshari Kamran , O&apos;Hara Brendan 
Published: June 2014

Summary
Steam-assisted gravity drainage (SAGD) has been improved consistently by experimenting with various solutions in both oil sands and heavy-oil fields in Canada (Butler 1994; Singhal et al. 1998). The SAGD process consists of two stacked horizontal wells and is proven technology in heavy-oil fields (Butler and Yee 2000). Employing the same concept of gravity drainage, SAGD-well placement convention has been revisited and challenged many times (Birrell and Putnam 2000; Edmunds 1991; Parappilly and Zhao 2009). Known to the industry, the cross-SAGD (also called XSAGD) (Stalder 2007) and J-shaped well steam-assisted gravity drainage (JAGD) (Larter et al. 2008) processes are two examples of fit-for-purpose well design and recovery schemes that require unique drilling practices. The Celtic pool, located in Lloydminster, Saskatchewan, is an active Husky Energy Incorporated (Husky) thermal field that includes 31 SAGD well pairs. In this heavy-oil pool, one of the SAGD well pairs (I3/I4; Well I3 as producer and Well I4 as the injector) experienced production downtime soon after coming into service. Following numerous unsuccessful service jobs, several re-entry options were suggested in order to recover remaining reserves. These included sidetracking Well I3, redrilling a new well from the same pad location, or commencing a new well from a different surface location. These cases were ranked, and in 2010, on the basis of a drilling-risk assessment, the new horizontal producer well (I3A) was drilled close to the existing well pair. Well I3A was placed counter currently below the existing injector well (I4) and set successfully parallel to the abandoned Well I3. Steam conditioning was completed in the first quarter (Q) of 2011, and the new SAGD well pair (I3A/I4) has been put on production successfully.
The new well pair was positioned in the opposite direction of a conventional SAGD-well-pair placement. This paper presents the original I3/I4 pair performance, the challenges, results of redrilling Well I3A, reservoir-simulation study, and recent field production of the I3A/I4 SAGD well pair.
Effect of Completion Heterogeneity in a Horizontal Well With Multiple Fractures on the Long-Term Forecast in Shale-Gas Reservoirs
Authors: Nobakht Morteza , Ambrose Raymond , Clarkson Christopher R. , Youngblood Jerry E. , Adams Rod 
Published: June 2014

Summary
Shale gas reservoirs have become a significant source of gas supply in NorthAmerica because of the advancement of drilling and stimulation techniquesenabling commercial development. The most popular method for exploiting shalegas reservoirs today is the use of long horizontal wells completed withmultiple-fracturing stages [multifractured horizontal wells (MFHW)]. Thestimulation process may result in biwing fractures or a complexhydraulic-fracture network. However, there is no method to differentiatebetween these two scenarios with production data analysis alone, makingaccurate forecasting difficult.
For simplicity, hydraulic fractures are often considered biwing whenanalyzing production data. A conceptual model that is often used for analyzingMFHWs is that of a homogeneous completion in which all fractures have the samelength. However, fractures of equal length are rarely if ever observed (Ambroseet al. 2011).
In this paper, production data from heterogeneous MFHWs (i.e., where allfracture lengths are not the same) is studied for reservoirs with extremely lowpermeability. First, the simplified forecasting method of Nobakht et al.(2012), developed for homogeneous completions, is extended to heterogeneouscompletions. For one specific case, the Arps' decline exponent is correlated tothe heterogeneity of the completion. It is found that, as expected, Arps'decline exponent (used after the end of linear flow) increases with theheterogeneity of the completion. Finally, it is shown that ignoring theheterogeneity of the completion can have a material effect on the long-termforecast.
We have assumed planar hydraulic-fracture geometries for our modelling inthis work and discuss the implications of this when more-complex fracturegeometries are created. This seems to be more common in shale gas reservoirs.We provide an example of low-complexity, planar fracture geometries creatednear an MFHW and observed on an image log at an offset well.
Shale Gas: Nanometer-Scale Observations and Well Modelling
Authors: Silin Dmitriy , Kneafsey Timothy J. 
Published: June 2014

Summary
Our studies of the underlying fundamental gas-recovery mechanisms from shale gas are motivated by expectations of the increasing role of shale gas in national energy portfolios worldwide. We use pore-scale analysis of reservoir shale samples to identify critical parameters to be employed in a gas-flow model used to evaluate well-production data. We exploit a number of 3D-imaging technologies to study the complexity of shale pore structure: from low-resolution X-ray computed tomography (CT) to focused ion beam and scanning electron microscopy (FIB/SEM). We observe that heterogeneity is present at all scales. The CT data show fractures, thin layers, and density heterogeneity. The nanometer-scale-resolution FIB/SEM images show that various mineral inclusions, clays, and organic matter are dispersed within a volume of few-hundred µm3. Samples from different regions differ sharply in the shape, size, and distribution of pores, solid grains, and the presence of organic matter. Although the samples have clearly distinguishable signatures related to the regions of origin, extremely low permeability is a common feature. This and other pore-scale observations suggest a bounded-stimulated-domain model of a horizontal well within fractured shale that accounts for both compression and adsorption gas storage. Using the method of integral relations, we obtain an analytical formula approximating the solution to the pseudopressure diffusion equation. This formula makes fast and simple evaluation of well production possible without resorting to complex computations. It ss a decline curve, which predicts two stages of production. During the early stage, the production rate declines with the reciprocal of the square root of time, whereas later, the rate declines exponentially. The model has been verified by successfully matching monthly production data from a number of shale-gas wells collected over several years of operation. With appropriate scaling, the data from multiple wells collapse on a single type curve. Pore-scale image analysis and the mesoscale model suggest a dimensionless adsorption-storage factor (ASF) to characterize the relative contributions of compression and adsorption gas storage.
Simulation of Noncondensable Gases in SAGD-Steam Chambers
Authors: Gittins Simon , Gupta Subodh C. , Zaman Maliha 
Published: June 2014

Summary
Cenovus Energy has been developing the Foster Creek and Christina Lake projects using the steam-assisted gravity-drainage (SAGD) process successfully. The SAGD process at both these projects has been operated at well above the initial reservoir pressure for extended periods of time and this has been simulated adequately using dead-oil models, which omit solution gas from the simulations. As we move into later stages in the life of the more mature well pairs at these projects, it is important to understand the role of noncondensable gases on the development of the steam chambers better in order to optimize the methane-coinjection, steam rampdown, and, ultimately, blowdown phases of operations. Cenovus is also testing reduced-pressure SAGD and solvent-aided processes (SAPs) at these projects, and simulations indicate that noncondensable gas will play a significant role in these processes. Hence, understanding the flow behaviour of noncondensable gases in SAGD steam chambers could have far reaching consequences for lowering the energy intensity and associated costs, and reducing the environmental impact of bitumen production while potentially increasing reserves. This paper presents the results of some recent simulations which are improving our understanding of the role of solution gas in SAGD and the impact of noncondensable gases on steam chamber development.
Innovative Coiled Tubing Water Shutoff Techniques in Horizontal Wells
Authors: Burov A. , Kharrat W. , Hussein N. 
Published: June 2014

Abstract
The wells in the southern area of Saudi Arabia are mostly horizontal wells in highly fractured carbonate reservoirs. Due to high water cut caused by water influxes through the fractures, some of these wells were dead or on intermittent production between 2005 and 2010. To increase oil production, we performed several water shutoff jobs using inflatable packers with mixed results.
The water shutoff candidate selection process starts with a reservoir and production data evaluation, followed by a coiled tubing (CT) logging run to identify the water source and adjust the required isolating fluids formulation and volume. Successful execution of the water shutoff treatment requires controlling the placement, inflation, injection, and disconnect of the inflatable packers.
Fiber-optic enabled coiled tubing (FOECT) systems, which enable real-time downhole data measurement, can optimize water shutoff treatment design, execution, and evaluation—increasing the success ratio.
For the job design, we ran production logging tools on the FOECT string to detect the water source, measure the bottomhole temperature required for the formulation of water shutoff fluids, obtain a gamma ray and/or casing collar locator (CCL) log, and get an X-Y open hole (OH) caliper critical. This helped us determine the best setting depth for the inflatable packer in the openhole section, and confirm the required water shutoff fluids volume.
The depth correlation for the packer setting was performed with a fiber-optic bottomhole assembly (BHA) gamma ray conveyed on CT. This enabled us to monitor and adjust the inflation of the packer, and the injection through it, in real time Then, the packer setting and release was confirmed with the world's first application of a fiber-optic, CT-conveyed tension and compression tool.
Recent production results showed significantly higher production with no more than 10% water cut. The integrated CT solution proved to be an effective water shutoff technique in these horizontal wells, and has potential to bring many wells around the world back to economic production.
Innovation and Successful Application for Calcium Sulfate Scale Removal in Gemsa Oil Field: A Field Study
Authors: Hamdy E. , Fahmy M. , Faramawy A. 
Published: June 2014

Abstract
Water flooding is the hinge pin for Gemsa Oil Field. Water injection is supplied from shallow water supply wells. Compatibility tests had indicated probable deposition of calcium sulphate scale on surface and subsurface production equipment. Calcium sulphate scale has been recognized to be a major operational problem. The bad consequences of scale formation comprised the contribution to flow restriction thus resulting in oil and gas production decrease. The nature of calcium sulphate scale is very hard and can’t be dissolved with known dissolver. Sister companies that has similar problem were always going to the mechanical remover options.
Extensive lab and field work was conducted to determine the suitable chemicals to dissolve calcium sulphate scale.
This paper describes the development and field application of chemical treatment to remove scale in an offshore 8" production line in Gemsa oil field. Continuous precipitation of calcium sulphate scale caused partial plugging of the pipeline. This partial plugging created a back pressure on production wells which decreased the productivity. The field production has been decreased to almost one tenth of the normal field production level1.
A thorough investigation was conducted to identify the composition and location of the scale, in order to recommend a suitable chemical to remove the scale, and to assess the effectiveness of the treatment method in the field.
Based on extensive lab studies, SAG-01 was tested and applied in production line to remove the scale efficiently, the program was designed taking into consideration the nature of the scale.
The treatment program included three - staged process: The use of an organic solventThe main treatment (SAG-01).The post flush stage (injection water),
The job results were outstanding, where as Production increased by about 2,000 BOPDLauncher pressure dropped by about 350 psi.Decrease the back pressure on our producing wells.Additional producing wells into production.Efficient cost /Bbl.
Experience of Multiphase Flow Measurement Systems Aapplication in Arctic Conditions
Authors: Lomukhin Alexander , Rymarenko Konstantin 
Published: June 2014

SummaryProblems of well production monitoring, flow assurance and control over excavation of resources stand especially serious in harsh Arctic conditions. In case of such difficulties as gas-condensate-oil saturation, high areal and vertical heterogeneity of the reservoir and essential reservoir overpressure strong needs in individual well productivity monitoring appears. This is the only approach to optimize reservoir development properly. Continuous online monitoring of fluid flow from the reservoir to refinery facility allows avoiding hydrate formation and wax-asphalten deposition, so prevent production losses.Now days several gas-condensate fields are under development in Russia. But the only technology recommended by licensing authority for the CGR metering is a large well testing separator. This recommendation has been brought out in 70s years of previous century. Large separators are quite dangerous by nature, cannot be fully automated, and must be equipped with additional heating devices and need expensive maintenance in Arctic conditions.On the license blocks belonging to Rospan International- a TNK-bp company- compact and highly-mobile non-separating multiphase flow metering technologies are being tested and improved. This paper is about more than four years experience of usage of Schlumberger Vx PhaseTester. Also Vx technology enhancements for gas- condensate wells done on Rospan International fields are described. Metrological studies of multiphase flow meters were also done before. Such studies are being carried out by Rospan International in collaboration with service companies- some of the results are published in this paper.
Near Wellbore Streamline Modeling: Its Novelty, Application, and Potential Use
Authors: Skinner J. H. , Johansen T. E. 
Published: June 2014

Abstract
Over the last 25 years streamline modeling has proven to be a valuable technique within the field of reservoir engineering, primarily with respect to heterogeneous reservoirs undergoing convection dominated flows. To date, most applications have been performed on a full field level. In this research, streamline modeling is applied to individual wells on a near wellbore scale. The stability of the technique is achieved via first principle modeling using a time of flight algorithm in cylindrical geometry utilizing logarithmic grid refinement. The modeling technique allows for an understanding of how near wellbore heterogeneities affect flow distribution and production. The model is expanded to evaluate various completion strategies, including a cased and perforated well with associated perforation and formation damage, as well as an open-hole completion with partial filter cake build-up.
To analyze the models, response surface methodologies are utilized. With respect to a cased and perforated well, the most statistically influential factors on both flow rate and skin are perforation permeability, number of perforations, damage zone permeability, damage zone radius, and perforation length, respectively. Various interactions are also significant, including perforation permeability with perforation length and damage zone permeability with damage zone radius. In relation to partial filter cake removal in anopen-hole completion, only the area/angle of coverage has a significant effect on the productivity of a well.
The model contains numerous simplifying assumptions, including single phase incompressible flow in two dimensions for heterogeneous medium. Nevertheless, it has proven to provide stable and reliable results. Although implemented in two dimensions, the techniqueremains very useful in evaluating completion strategies and overall effectiveness, thereby offering significant potential to increase industry profitability. It is emphasized that an extension to three dimensional problems is straightforward since the third dimension is linear along the well trajectory.
Further research incorporating the works of streamline modeling in Cartesian geometries will lead to a reduction in the simplifying assumptions, allowing for compressible multiphase flow and the inclusion of gravitational effects.