bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effects of Shear Planes and Interfacial Slippage on Fracture Growth and Treating Pressures
Authors: Barree R.D. , Winterfeld P.H. 
Published: December 2007

Abstract
The equations used in current hydraulic fracture simulators are based on plane-strain solutions, or use a complete surface integral solution for fracture width. Assumptions inherent in these solutions control the stress field surrounding the fracture tip and the stress intensity developed at the tip which, in turn, controls the rate of fracture growth and containment and the predicted net pressure. The overriding assumption made in these solutions is that the entire rock mass is elastically coupled so that all stresses and deformations interact.
Many reservoirs that are hydraulically fractured are susceptible to complex fracturing which can invalidate the assumption of elastic coupling. Microseismic monitoring of fracture growth indicates that energy is lost to shear failures around the fracture. During hydraulic fracturing high fluid pressures, often exceeding both the minimum and maximum horizontal stress (fissure opening pressure), result in the reduction of the normal stress acting across natural fissures. This allows free shear or slippage along natural fracture planes in reservoirs or cleats in coal. When shear or slippage occurs elastic coupling in the rock mass is lost and each shear block deforms as a separate unit. This shear decoupling results in tremendous reduction in created fracture width and leads to high frictional pressures (low transmissibility) and difficulty in placing proppant, especially large proppant.
The purpose of this work is to suggest that current fracture models are missing what could be a dominant containment mechanism in the fracturing of fissured reservoirs, coals, and soft rocks and that further work is required to fully understand the implications of slippage and shear failure on treatment designs.
P. 11
Significant Production Enhancement of Extended Reach, Prolific Gas Lift Oil Wells -- Case History of Systematic Problem Resolution
Authors: Hahn D. , Yu D. , Tiss M. , Dunn R. , Murphy D. 
Published: December 2007

Abstract
Most oil wells producing from the Glauconite YY Pool of the Lake Newell field in Southern Alberta, Canada have very high flow capacities. Wellbore operations are complicated by the configuration of the slant wells with surface angles of 45 that can reach 75 at bottom and horizontal displacements in excess of 6600 ft. During the development of this field, it was determined that there was a full cycle economic advantage to utilize gas lift as the primary artificial lift scheme because of the extended reach slant wellbore configurations. In 1996 opportunities to economically enhance production and accelerate recovery were identified in several of these gas lifted wells.
Wellbore performance could not be matched to any theoretical tubular flow simulation thus a significant effort was made to understand these differences which, after consultation with various international experts, still did not offer a definitive explanation. Some of the production impairment mechanisms considered were phase separation and stratification of fluids (water, oil, and gas) in the tubing, wax/paraffin formation, and unknown fluid rheologies. An attempt to production log one well was unsuccessful because the well ceased to produce with the decreased flow diameter of coiled tubing inside 2.875 inch production tubing. Since some wells are producing at drawdowns as low as 5%, significant production enhancement opportunities still needed to be pursued along with identifying the welibore production impairment mechanism.
Larger diameter tubing (3.5 inch) was run in a 70% water cut well increasing production from 850 BLPD to 1130 BLPD, which was still significantly lower than theoretical rates of 3150 BLPD. A demulsifier chemical, that the cross functional property team had previously identified as being effective in reducing high pressure drops in surface piping, was introduced into the injection gas stream. Two days after chemical injection began, the well started to produce at theoretically predicted production rates; however, it was very unstable and would cycle to original rates for long periods of time followed by very high rates again due to changing annular fluid levels. This prompted the installation of a chemical injection capillary tubing to bottom resulting in sustained production of 3000 BLPD: a 150% increase and near the theoretically predicted rates.
This paper will sequentially outline the diagnostic and operational methodology used to solve the very difficult problems encountered with unconventional wellbores and fluids. It will emphasize the value of teamwork in problem resolution and demonstrate that perseverance in working through a problem or issue follows a modified Shewhart Cycle. The well improvements outlined in this paper have significantly contributed to enhancing the economic oil recovery of the YY Pool.
P. 67
A Simplified Approach to Couple Wellbore Flow and Reservoir Inflow for Arbitrary Well Configurations
Authors: Ouyang Liang-Biao , Aziz Khalid 
Published: December 2007

Abstract
A wellbore/reservoir flow coupling model is developed. It can be applied to a parallelepiped drainage domain consisting of any number of wells with any number of laterals of arbitrary configurations. Reservoir inflow for entire time period (from early transient to late pseudo-steady state) is handled in the coupling model by integrating the instantaneous point source/sink solution over both time and space. Pressure drop along any lateral in the well system includes those caused by wall friction, gravity, and acceleration due to wall inflow or outflow. Effects of wall mass transfer on wall friction and kinetic energy change are taken into account.
A computer package has been developed and used to perform a series of sensitivity studies which lead to several important and interesting observations. The coupling model may be applied to determine well productivity, well index, wellbore pressure profile, wellbore inflow or outflow distribution for any time in the well's production/injection life.
P. 79
Preconditioned Newton Methods for Fully Coupled Reservoir and Surface Facility Models
Authors: Byer Thomas J. , Edwards Michael G. , Aziz Khalid 
Published: December 2007

Abstract
The fully implicit coupling of surface facilities with a reservoir model can lead to a significant increase in computing time. The focus of this paper is on the development of methods that can minimize the impact of the facility model on the global solution procedure. A local grid refinement preconditioner is developed to accelerate convergence of the full flow field implicit simulation.
P. 181
Modeling the Diffusion Flux Between Matrix and Fissure in a Fissured Reservoir
Authors: Lenormand R. , Le Romancer J.F. , Le Gallo Y. , Bourbiaux B. 
Published: December 2007

Abstract
Numerical simulation of recovery in fractured reservoirs by simulators requires determination of transfer parameters between fracture and matrix. These large-scale transfer parameters accounts for capillary, diffusive or gravity effects and can be derived by up-scaling the local physical mechanisms. The transfer driven by capillary or gravity forces is easy to model, but there is no simple model for diffusion. Our study was aimed to calculate the transfer of a component by diffusion as a function of fracture geometry, fluid velocity in the fracture, and fluid compositions in fracture and matrix. The diffusion flux is calculated assuming a uniform fluid saturation at the interface between matrix and fracture and a laminar flow in the fracture. The coupled flow and concentration equations are solved along the width of the fracture and then integrated over its length. The resulting diffusion flux is given by a simple analytical formula. Calculations were then compared to experiments performed at reservoir conditions with pure methane injected in the fracture and binary mixtures in the matrix (Cl, C5). The results were in very good agreement, without any adjustable parameters. Finally, it is shown how the calculations can be implemented in a reservoir simulator. The fracture is considered as a porous block but then cannot directly account for the diffusion flux as a boundary condition. The only way to model the diffusion transfer is to calculate an effective diffusion coefficient which accounts for the diffusion transfer but also the grid discretization. A good agreement is obtained without any adjustable parameters between numerical simulations and experiments.
P. 259
Determination of Residual Oil Saturation Using Enhanced Diffusion
Authors: Akkurt Ridvan , Marschall Dave , Eyvazzadeh Ramsin Y. , Gardner John S. , Mardon Duncan , Dunn K.J. 
Published: December 2007

Abstract
The potential use of NMR as a direct indicator of hydrocarbon saturation via techniques such as the Differential Spectrum Method (DSM) has generated significant interest in the petrophysical community in recent years. Although originally developed for applications involving natural gas, the DSM has also been used successfully in light hydrocarbon environments. However, success has been limited to the low end of the viscosity spectrum because of the T1 separation requirements between the brine and hydrocarbon phases.
The T1 separation requirement in higher viscosity applications can be eliminated by using the Enhanced Diffusion Method (EDM), where diffusion is turned into the dominant relaxation mode for the wetting brine phase. Given that brine is more diffusive than the hydrocarbons, the longest apparent T2 from the brine phase can be made short enough to cause separation between the two phases in T2 space, thereby eliminating the need for T1 separation. Wait time manipulation can then be used to quantity hydrocarbon volumes when the two phases are separated in T2 domain.
This paper focuses on the determination of residual oil saturation using EDM, while also providing guidelines for job screening and acquisition parameter selection. Several case histories provided are used to illustrate basic concepts and different methodologies available.
P. 267
Holbrook Anticline, Arizona: An Exposed Analog for Fractured Reservoirs Over Salt- Dissolution Fronts
Authors: Neal James T. , Lorenz John C. 
Published: December 2007

Abstract
Fractured late Paleozoic and Mesozoic strata at the southern edge of the Holbrook basin in east-central Arizona overlie an active salt-dissolution front. Where the evaporates have been dissolved, the overlying strata have been offset by approximately 100 m, creating a draped monocline called the Holbrook Anticline. This dissolution-front monocline extends along a northwesterly trend for more than 100 km. Strata immediately over the dissolution front have been stretched by bending during migration of the front. The regional fractures that were present in these strata have been reactivated in extension, and some of the fractures at the crest of the anticline now have "apertures 1, up to several meters wide. Large wedges of rock between fractures are locally displaced downward as much as 15 ml forming small grabens. Many of these grabens were enlarged to form sink holes hundreds of meters across that are filled with talus breccia that formed from collapse of the overlying strata. Buckling of the surficial strata is also present in localized compressional zones associated with bending at the toe of the anticline and elsewhere. This suite of features comprises a model that can help to refine interpretations of the reservoir characteristics of fractured oil and gas fields associated with similar, deeper, dissolution fronts, such as the Silo field in Southeastern Wyoming.
P. 337
Risk Analysis: Lessons Learned
Authors: Alexander J. A. , Lohr J. R. 
Published: December 2007

Abstract
During the past 30 years the petroleum industry has generated significant information on risk analysis methods for exploration and development projects. However, some people continue to ask the question "Is it worth the effort?" or comment "It has not worked for me."
The authors have learned many lessons during the past few years that resulted in an improved risk analysis process. The following recommendations will ensure a successful risk analysis process. Written guidelines are necessary to avoid misapplication of established methods. These guidelines should be well documented, communicated to everyone involved in the process and regularly updated.Oversight of the risk evaluation process is necessary to maintain consistency, eliminate bias, and check for misinterpretations that occur through lack of understanding.Risk analysis training for both technical professionals and management is essential.Evaluation software should be accessible, standardized, easy to use and adaptable to changing technology and needs.An understanding of dependency between variables is vital.Risk methods should be adaptive to allow integration of new techniques, such as seismic direct hydrocarbon indicators (DHCIs), into the process.Results from risked projects should be understood and tracked closely over time to facilitate adjustments and enhancements to the methods.
Understanding Fracture Performance by Integrating Well Testing & Fracture Modeling
Authors: Cipolla C.L. , Mayerhofer M. 
Published: December 2007

Abstract
This paper presents case histories and field data that details the application of well test data to "calibrate" fracture models, understand fracture performance, and optimize treatment designs. The paper includes field results from gas reservoirs in the Rocky Mountains, West Texas and East Texas. In addition, the case histories illustrate the application of postfracture pressure buildup data to identify reasons for fracture treatment problems and confirm treatment success. The paper also includes a novel data set that illustrates fracture performance from a liquid CO2 stimulation (no sand, no water) in West Texas. The case histories illustrate the importance of integrating well test data with fracture treatment optimization, showing how this process can improve our ability to reliably make multi-million dollar decisions concerning proppant selection and fracture treatment size.
P. 293
Well Performance and Completion Effectiveness in the Baldy Butte Field, Washakie Basin, Wyoming
Authors: Cramer Dave , Stallings Darrick 
Published: December 2007

Abstract
The Baldy Butte field is located in the East Washaltie subbasin of the Greater Green River Basin and is several miles east of the prolific Echo Springs/ Standard Draw Almond bar sand trend. Wells are completed in the upper 300 to 400 ft of the Almond formation (Upper Mesaverde), at a true-vertical depth of around 8000 ft. Production is wet-gas (10–14 bbl of condensate mmscf gas) and occurs from naturally fractured low-stand deltaic, marine and fluvial point-bar sand deposits. These sands are over-pressured (0.57 psi/ft gradient), possess an average permeability of 0.04 md, and exhibit variable continuity within the field. Most of the field development has occurred over the last 2 1/2 years, and has involved contrasting well-completion methods, each specific to the three companies that operate wells in the field. This paper documents an analysis of 29 recent, contiguous completions in the Baldy Butte field, comparing the effectiveness of the three contrasting completion stimulation methods. The evaluation was based primarily on use of the reciprocal productivity index (RPI) graphical production-analysis method. Using RPJ, daily production and wellhead pressure data for each well was used to dissect well performance, obtaining information on reservoir flow capacity, stimulation effectiveness, reservoir flow geometry, drained area/volume, and produced liquid management. Distinct differences in reservoir quality and effectiveness among the contrasting completion methods were observed.
P. 307
Prudhoe Bay Field: Facility Consolidations Pave the Way for an Economic Future
Authors: Eager K.D. , Briscoe M.D. , Bolduc R.A. 
Published: December 2007

Abstract
The Prudhoe Bay Field on Alaska's North Slope has produced for twenty-one years. Prudhoe's gas and water production rates are at historic highs, but the oil production rate has declined to less than one-half of the peak rate achieved in the 1980's. As a result, significant excess oil treating capacity exists, with water and gas handling capacity constraining the current oil production rate. The owners of the Prudhoe Bay Unit ("PBU") developed a major facility consolidation plan in 1997 designed to rationalize this excess oil treating capacity while preserving existing gas and water handling capacity. The reconfigured facilities are expected to provide sufficient capacity at a lower cost to accommodate projected oil, water and gas production rates over the remaining life of the Prudhoe Bay Field.
This paper describes the Prudhoe Bay Surface Facility Optimization Project, from conceptual engineering initiatives in 1996. through preliminary engineering, economic justification, attainment of support from operations personnel and approval by the working interest owners of the Prudhoe Bay Field. Technical challenges and the challenges of projecting benefits associated with the consolidations were resolved through networking and technical discussions throughout the BPX, ARCO and Exxon world-wide organizations. The ultimate approval of the plan by the PBU Working Interest Owners is a clear example of teamwork and information sharing on a global scale.
P. 275
Oil Shale Outlook
Authors: Cameron Russell J. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the 1974 Eastern Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Washington, D.C., Nov. 14–15, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the SPE magazines.
Oil shale is somewhat like the "old-maid" aunt. She has always been a good prospect for marriage but each suitor seems to back away at the church door. There are still a good many admirers but most think she is a bit too expensive to take to the alter right now without a fairly substantial dowry. There also is a feeling that some members of her family really don't want to see the old gal married anyhow.
So, she remains an aging maiden wistfully awaiting a lover rich enough, bold enough, and dedicated enough to overcome the obstacles fate placed in her path.
What then is the outlook for oil shale. It is pretty much the same as has been said of the outlook for Brazil. Brazil (and oil shale) have a great future, always have had a great future and always will have a great future; but the present is impossible to predict.
Look at what happened this year. On January 8, $210 million was paid for a 5,120-acre Federal oil shale lease, the highest per acre price ever paid for a petroleum prospect. Other leases in the petroleum prospect. Other leases in the same sale brought from $45 million to $117 million in high bids. Yet, in, October the Colony group (Atlantic Richfield, Ashland, Shell and Tosco) deferred their commercial shale venture on private lands after spending 10 years and more than $50 million preparing for it. Adding further to the paradox, the Colony group was high bidder on the $117 million Federal lease.
And consider this. A prestigious Federal Interagency Task Force studying the role of oil shale for Project Independence arrived at the conclusion that under an accelerated program a 1,000,000 B/D industry could be operational by 1985 without violating Federal environmental regulations or exceeding other constraints.
The Effect of Fluid Loss on Fracture Extension
Authors: Davis J.G. , Reynolds J.J. , Coffer H.F. 
Published: December 2007

Abstract
Field trials have shown that superior fracturing treatments may be obtained when a low fluid loss oil is employed as the sand carrier. Such a carrier now can be made very economically from lease crude oil by the use or a fluid loss controlling additive.
Experimental fracturing tests were conducted to determine the relative importance or fluid loss and viscosity in fracture extension. It was found that sand concentrations as high as 8 lb or sand per gallon could be displaced into the formation at a 4 bbl/minute pumping rate using a treated lease crude of low viscosity (12 cp) and low fluid loss. During another test 48,000 lb or sand at 4 lb/gal were displaced using the same treated crude and pumping rate. Other field tests have indicated that low fluid loss, low viscosity fluids may be successfully used where high fluid loss, high viscosity fluids are not effective. These results demonstrate the importance or fluid loss control in fracture extension.
The importance of low fluid loss is rapidly being recognized by the industry. Hundreds or wells have been fractured using lease crude with a controlled fluid loss. Fewer sand-outs are encountered and production increases tend to be more sustained. The converted oils have performed very well in formations that have been difficult to fracture in the past. Such rotations include chats and conglomerates and reservoirs with temperatures in the 200°F to 300°F range.
Both laboratory and field results have shown that crudes treated to reduce the fluid loss are fully compatible with the various gelling materials now available. The very low fluid loss gel that results from this combination is advantageous in many instances. With proper treatment design, the selection of crude oils is now almost unlimited. The development or the hydraulic fracturing process has occupied only a few years in the history of the oil industry. During this brief period, however, fracturing has become the major method for production stimulation and its application has led to the reopening of many oil fields formerly classed as depleted.