bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Feasibility Studies of Natural Gas Flooding in Ansai Field
Authors: Zhongchun Liu , Hou Jirui , Zhenhuan Gao , Wu Yanli 
Published: December 2007

Abstract
Ansai field is a typical field with low permeability, low pressure, low production and the water flooding is inefficient. In order to explore an effective developing method for increasing the production and ultimate recovery, we carried out the feasibility studies of natural gas flooding. This paper analyses the feasibility of natural gas flooding from the geological condition of Ansai field at first, then introduces the high pressure slim tube tests for determining MMP of injection gas and reservoir oil and prediction of MMP with published correlation. The high precision correlation has been selected for predicting the composition of injection gas in miscible displacement. The performance of natural gas flooding have been simulated using MVIP simulator. The results shows that Ansai field shares the geologic conditions for natural gas flooding. The MMP of lean gas and Ansai reservoir oil is above 32MPa, and the average reservoir pressure is only 8.81 MPa in Ansai field, so the lean gas flooding is immiscible displacement at Ansai reservoir condition. If accomplishing a miscible displacement at the same condition, the composition of injected gas must be changed by increasing rich gas content, the content is 80%C2H6. The results of numerical computations shows that the recovery ratio of natural gas flooding (26.3%OOIP) is more than of water flooding (20.6%OOIP).Obviously, the natural gas flooding is a hopeful EOR method in Ansai field. These studies provides scientific evidence for the policy of natural gas flooding in Ansai field.
P. 371
Comparison of Well Log and Welltest Data in a Naturally Fractured Formation
Authors: Engler T.W. , Baiar T. 
Published: December 2007

Abstract
Three primarily sources of information available for reservoir description are cores, well logs, and welltest data. In this work, a comparison of formation storage capacity is made between well log and welltest information for a dual porosity, naturally fractured formation. Over the years, two independent parameters, the partitioning coefficient in well logging and the fracture storage coefficient in well testing, have been available to characterize these types of reservoirs. A relationship will be developed between these two parameters.
By definition, well log and welltest data investigate different volumes of the formation; i.e., a variation in scale exists. Therefore, it is likely that when both parameters are within reasonable agreement the fracture storage (Fracture intensity?) is equal within the two test volumes and may be extrapolated as being representative of the given reservoir. However, if the parameters are different, then fracture storage is a function changing with distance from the wellbore.
Application of these principles was tested on a known naturally fractured, sandstone reservoir in the Rocky Mountains. Analysis of this field example resulted in agreement between the two parameters; suggesting a widespread fractured volume. This conclusion confirms the geologic analysis of the area which was described as tectonically active and highly faulted.
P. 51
Enhancing Stimulation Candidate Selection Through Data Integration for 3D Hydraulic Fracture Modeling
Authors: Boonen P. , Byrd A.C. , Frisch G. , Kessler C. , Kubelka G. , Nixon Mark 
Published: December 2007

Abstract
Because of the differences in format and data density, wireline log data are not always used optimally in 3D hydraulic fracture modeling. They do provide, however, the most comprehensive and continuous parameters for borehole stress profile, permeability index, elastic moduli, lithology, porosity and fluid saturation's. A new method is presented to provide all the available logging data in a format suitable for direct input in 3D hydraulic fracture models. An automatic zoning technique divides the data into consistent intervals based on stress contrast. The representative design parameters are then computed for each zone. The outputs are a blocked stress profile and a set of zoned fracture design parameters. This new product provides a synergistic approach to hydraulic fracturing in which wireline logs and rock mechanical analysis are fully utilized together with pump-in tests to optimize the execution and economics of the field development process.
The technique is illustrated by application to a particular South Texas gas field which has suffered severe production decline during the last two years. The object was to identify and treat potential producing zones in all existing wells to increase production. The new log was generated using existing openhole logging data. Based on this log, one well was bypassed for treatment altogether, saving $500,000 to $700,000 on a stimulation that would have had a marginal result at best. In another well, the log was used in combination with a Fluid Efficiency Test/Step Rate test to show essentially no leak-off, and hence, very low permeability in one zone.
P. 107
Development of the Boundary Element Method for A Horizontal Well in Multilayer Reservoir
Authors: Jongkittinarukorn K. , Tiab D. 
Published: December 2007

Abstract
Pressure transient analysis for horizontal wells has gained a lot of attention recently due to the increasing number of horizontal wells. Interpretation of horizontal well test data is much more difficult than for a vertical well. Due to heterogeneity, application of single-layer models fails to interpret the reservoir properties. Numerical methods are essential for a horizontal well in multilayer reservoir with complicated wellbore configuration and boundary conditions.
This paper presents a boundary element method for solving pressure transient behavior of multilayer reservoirs. Two types of boundary conditions, Dirichiet and Neumann, can be handled by the proposed technique. The boundary element method yields several advantages over the conventional finite- different and finite-element methods.
The developed algorithm is successfully applied to some simple cases with known analytical solutions including a finite linear aquifer, a horizontal well in closed reservoir, and a horizontal well in a multilayer reservoir.
P. 317
Multiple Pad-Acid Fracs in a Deep Horizontal Well
Authors: Nelson R.L. , Dyck W.C. , Jamieson F.M. , Jenkins R.A. 
Published: December 2007

Abstract
Panther River is a deep sour gas field situated in the thrust fault region of the Canadian Rocky Mountains operated by Shell Canada Ltd. In 8 years of production, only 3.3% of the 1 TCF of gas in-place has been produced from this low permeability reservoir. A plan was developed to improve the current production by drilling horizontal sidetracks from the existing wells and conducting multiple stimulations along the horizontal length.
Fracture stimulations in this reservoir posed several unique challenges. The reservoir is deep and in a thrust faulted region with expected bottom-hole fracture pressures as high as 130 MPa (18900 psi). This, along with the presence of 2% hydrogen sulfide, created very demanding criteria for the tubing and associated equipment used to isolate the individual fracs. The high pressure and large acid volumes required reliability issues to be overcome in order to utilize conventional frac pumpers. The high rock stresses required deep channels to be etched by the acid to compensate for post frac deformation of the rock. With a radial fracture propagating from a horizontal wellbore, special attention was paid to the interaction of the fracture creating pad fluid and the following acid stage. To our knowledge, it is the first time that the pad fluid was densified with 19% salt in order to match the density of the acid. This paper details these design aspects as well as describing the execution, highlighting the excellent performance of the equipment and frac fluid, along with some of the unexpected challenges that were overcome.
P. 363
Proppant Flowback Control in High Temperature Wells
Authors: James Simon G. , Samuelson Michael L. , Reed Glenn W. , Sullivan Steven C. 
Published: December 2007

Abstract
The control of proppant flowback following fracturing operations can be obtained by several different methods such as resin coated proppant, inorganic fibres or polymer strips. However, each one of the presently available technologies has its limitations, e.g. resin coated proppant cannot generally be used above 190 C (374 F) and requires an activator below about 70 C (158 F), and thermoplastic strips cannot be used above their melting point. Current fibre technology is normally limited to reservoir temperatures below 150 C (302 F), provides only short term control in carbonate reservoirs and cannot be used in situations where the fibres may be exposed to HF. A new high performance fibre for proppant flowback control has been developed to overcome these limitations. Laboratory testing has shown that these fibres are resistant to steam, diesel, xylene, Hcl, and mud acid at temperatures up to 250 C (482 F) for periods up to 7 months. In addition, proppant flowback control measurements at high temperatures have confirmed that the fibres retain excellent proppant flowback control properties. Results of field testing in deep, hot (177 C (350 F) carbonate reservoirs have confirmed the performance of the new fibre.
P. 523
Convection/Encapsulation in Hydraulic Fracturing
Authors: Shah Subhash N. , Asadi Mahmoud 
Published: December 2007

Abstract
New information is presented on the phenomena of proppant convection and encapsulation in the hydraulic fracturing treatments. To fully comprehend this phenomenon, a unique parallel plate flow cell is used which mimics field conditions and is integrated with a fiber optic vision system. The vision system is used to enable the visualization of proppant convection/encapsulation within the fracture. The experimental study involves pulse injection of both 6 and 10 ppg 20/40 mesh sand slurry of 35 lblMgal borate-crosslinked guar into various fluid media under static condition. Data analysis shows that proppant convection/encapsulation is a density/viscosity related mechanism. It is indicated that encapsulation (downward motion of proppant) dominates particle settling in a low viscous medium such as water or linear gel. This phenomena, however, diminishes as viscosity of the lower medium increases. In other words, particle settling within the slurry cluster dominates proppant encapsulation and hence convection. Therefore, it is ascertained that there exists an optimum viscosity value for a given range of density where the influence of density to form encapsulation and convection is inhibited. According to this study, a medium viscosity of 40,000 cp is suffice to sustain a 10 ppg 20/40 mesh sand 35 lblMgal horate-crosslinked slurry and to prevent development of proppant encapsulation/convection.
P. 531
Practical use of Neural networks in Tight Gas Fractured Reservoirs: Application to the San Juan Basin
Authors: Ouenes A. , Zellow A. , Basinski P.M. , Head C.F. 
Published: December 2007

Abstract
An innovative approach that uses neural network technology is developed to identify highly-productive "sweetspots" in the naturally fractured upper Dakota Formation, San Juan Basin, northwest New Mexico. Dakota estimated ultimate recoveries (EUR) are predicted through the vertical and horizontal integration of thirteen reservoir properties taken from three horizons over a 24-township area. The vertical information includes pay thickness, and resistivity (geological facies) from three gross sand units that contribute to the comingled upper Dakota production.
The horizontal information includes, thickness, and resistivity maps for each sand unit as well as structural property maps over the entire 24 townships area. Using a neural network, relationships are established between the thirteen geologic parameters and fracture intensity inferred by the EUR. These geologic models indicate that the parameters that control upper Dakota production are in order of relative importance: thickness, resistivity and structure. The derived relationships are used to predict "sweetspots at locations without well control."
P. 573
Near Critical Gas Condensate Systems: Effects of IFT on Gravity Drainage
Authors: Ceragioli P. , Masserano F. 
Published: December 2007

Abstract
The paper is devoted to show how different estimations of the interfacial tension between oil and gas phases can really affect the overall production evaluations. Obviously such effects are significant only for rich gas condensate reservoirs (liquid drop out &gt;10%).
Commercial reservoir simulators usually calculate interfacial tensions by the parachor method, which is known to underestimate low interfacial tensions between almost equal phases. In fact the parachor method fails just for those values (low values) which are critical.
Besides gradient theory, which is founded on statistical mechanics and therefore completely different from the parachor method, the other procedures are mainly derived from the original parachor method. Such new methods, suitable for calculating low interfacial tensions, can be grouped into two main families: a first group where pure component parachors are modified with respect to the original ones, and a second group where the critical exponent is changed, while parachor values of pure components are just the classical ones. Moreover two kind of mixing rules can be considered for this kind of methods: one founded on the principle of corresponding states and a second one, the Weinaugh-Katz parachors mixing rule.
After a short overview of the methods for the evaluation of the interfacial tension for mixtures and a discussion on the so- called critical exponent, each of them is used for the evaluation of the interfacial tension of mixtures, whose experimental values have been found in literature.
Moreover a real fluid has been taken in account. A synthetic reservoir has been considered and gravity drainages corresponding to the different interfacial tension evaluations, obtained by using the different methods, has then been performed on each of these fluids. All the results are then compared. The comparison shows the importance of the selection of a proper calculation method for the interfacial tension, also to consider a reliable recovery estimation.
P. 169
A Different Approach to Coupling a Reservoir Simulator with a Surface Facilities Model
Authors: Trick M. D. 
Published: December 2007

Abstract
Hepguler, Barua, and Bard1 recently described the integration of a commercial reservoir simulator and a commercial production network simulator using the Parallel Virtual Machine interface2. This paper outlines a somewhat different procedure, based on the same interface, that has been used to couple the same commercial black oil reservoir simulator ECLIPSE3 to a different surface model, namely the gas deliverability forecasting model FORGAS4. For a given case, this new procedure yielded a significant reduction in computation time (a factor of about 30), when compared to the Hepguler et al model, without any loss in accuracy or function. A distinct advantage of this new coupled system is that it is available commercially, unlike the previously described integrated models which were proprietary developments, not available to other companies.
Performing In-situ Stress Tests with Water in Underpressured, Low Stress Zones
Authors: Fairchild Nelson R. 
Published: December 2007

Abstract
With the increased use of 3-D fracture simulators, the need for accurate and affordable formation stress tests has arose. One of the main factors in keeping the test cost down is conducting the stress test with water. In most formations, the stress gradient is high enough (i.e. &gt;0.433 psi/ft) that water can be used, but there are many formations (Berea, Weir, Devonian Shale) that have stress gradients lower than 0.433 psi/ft. When this situation occurs, the hydrostatic pressure of the water can fracture the formation and the well goes on vacuum. This leads to problems establishing constant injection rates and pressures that are usually obtained before monitoring pressure falloff. In the past, formations with low stress gradients used nitrogen for the test fluid, thus keeping the hydrostatic pressure below frac gradient. This method works but is extremely cost prohibited.
This paper explains the problems that can occur when testing low stress gradient formations, and procedures that can be used to gain accurate formation stress profiles using water and a downhole shutoff tool with equalizing ports.
P. 361
Evaluation of Eastern Canada Offshore Gas Potential and Its Impacts on the Market Share in the North American East Coast
Authors: Vikas Shree , Baron Bob , Godec Mike , Ribar David 
Published: December 2007

Abstract
This study provides a comprehensive evaluation of the production, reserves and economic potential of natural gas extraction and transportation from Nova Scotia offshore (Sable Island) plays. Newly available information from Canadian Gas Potential Committee (CGPC) and other private data vendors was integrated into a comprehensive Gas Systems Analysis Model (GSAM), which is a gas supply, demand and transportation model developed by the U.S. Department of Energy (DOE).
Based on the preliminary model runs it has been found that offshore resources in Sable Island have the potential for significant future production. The recovery potential could be greater than the Sable Offshore Energy Project (SOEP) design. SOEP taps only 5 TCF of original gas in place (OGIP) and the total estimate of OGIP could be as high as 18 TCF. Aggresstive advancement of technology and a healthy gas price could warrant a production rate of around 600 mmcfd that is 50% higher than the planned SOEP design. Under such scenario about half the added production will generate incremental demand in the North American East Coast.
Carbon Dioxide Generation in Tugu Barat-C Field and Role in Hydrocarbon Migration
Authors: Prakasa Y. , Hartanto E. , Sulistyo D. 
Published: December 2007

Abstract
Six vertical and directional drillings in Tugu Barat (TGB) field have been proven to be oil and gas production wells. They are infiltrating three hydrocarbon reservoirs, consecutively from the oldest, the Lower Miocene Baturaja Formation, the Middle Miocene Zone 14 and Zone 16 of Upper Cibulakan Formation. Baturaja Formation is composed by limestone intercalated with shale. While the thin Zone 14 and Zone 16 are composed mainly by limestone.
High Carbon Dioxide (CO2) concentration examined in wells results various concentrations without any pattern vertically or horizontally. This gas concentration has been being an interesting phenomenon. Intensive geochemical and petrophysical experiments are needed to predict the sources and process of the CO2 and the effects of CO2 generation in migration and production rates.
Two possibilities have been concluded to be answer of the problem : CO2 is generated from Decarboxylation of coals in the Upper Oligocene-Early Miocene Talangakar Formation or is accounted for by dissolution of the Baturaja carbonate reservoir by formation water, although questioned, has caused in enhancement of CO2 generation.
CO2 generation plays role, although minor, in secondary porosity (fractures). Gas generation, usually causes an over- pressuring inside the formation due to the increasing pore volume. The Decarboxylation is a rapid and ephermal process and can be associated with dissolution of carbonate material.
P. 411
Reservoir Description Techniques Improves Completion Economics in Moxa Arch Frontier Development Project
Authors: Schubarth S. K. , Chabaud R. A 
Published: December 2007

Abstract
The Frontier formation located on the Moxa Arch in southwest Wyoming is a "tight" gas sand that has produced significant gas reserves. Over 700 wells have been drilled and completed in the area covered in this investigation. Hydraulic fracturing is the primary means of completion stimulation and treatments have varied in size and fluid type over the 20 years of development. Many treatment designs and results have been reported in the literature.1,2,3,4,5,6
In designing hydraulic fracture treatments attempts are made to "optimize" the economic return through the use of reservoir and fracturing computer models. The design of the "optimized" treatment and the estimated economics depend on the estimation of many reservoir properties. The most important of these is the estimation of permeability. Most often an average permeability for an area of a field is used. This may lead to a general "optimized" design but not an individual, well specific design. It is only when we can design for specific well conditions that a truly "optimized" treatment design can be achieved.
In this paper we will present a reservoir description technique which has proven successful at predicting the in-situ formation permeability and allowed for intelligent decisions about completion design to be made. Detailed analysis of standard openhole well logs is used to provide this permeability estimation. The ability to predict production response in over 70 wells is the proof that this technique provides valuable information to make completion decisions. We will present the results of these analyses and the production results. We will also quantify the benefit or detriment of different completion designs used in the study area by comparing well response normalized for reservoir quality. The authors believe that the methodology used can be applied to similar reservoirs to achieve similar results.