bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Overview of Current Acid Fracturing Technology with Recent Implications for Emulsified Acids
Authors: Li Yan , Sullivan R. B. , Rozieres Jean de , Gaz G. L. , Hinkel J. J. 
Published: December 2007

Abstract
The current acid-reaction testing methods for determining mass transfer and kinetics parameters are reviewed. Published acid fracturing models used in the industry are compared in terms of the basic equations, boundary conditions, solution methods and mass transfer considerations.
A sensitivity study (using a surface concentration model) shows the mass transfer coefficient to be the most important parameter which affects the shape of the concentration profile. The current industry standard correlation (Williams-Nierode) for determining the mixing coefficient is compared to laboratory results from history matching to determine the effective mixing coefficient for both Newtonian and non-Newtonian fluids. The laboratory results in the domain investigated (Reynolds numbers from 1 to 100) are generally lower than the Williams-Nierode correlation.
A quality control procedure for obtaining repeatable results from the rotating disk test is presented. This technique is also applied to power law fluids.
An emulsified acid field example is also presented to show the effectiveness of acid fracturing as a viable alternative to proppant fracturing.
Acheson D-3A Pool: Primary to Secondary HCMF—40 Years of Performance
Authors: MacLean D. A. , Edwards K. A. 
Published: December 2007

Abstract
This paper describes the development and performance of the Acheson D-3A pool from discovery through three depletion mechanisms over a 40 year period.
Discovered in 1950, the Acheson D-3A pool is a Devonian-aged dolomotized reef containing both vuggy and matrix porosity averaging 11.4% field-wide. Excellent reservoir performance results from horizontal permeabilities generally greater than one Darcy, and vertical permeabilities two to three orders of magnitude smaller than the horizontal permeability.
The development of the pool is traced from discovery through delineation drilling with emphasis on the type and quality of log and core data obtained, six years of primary production, followed by a gravity stable vertical waterflood, and, 30 years later, the design and implementation of a gravity stable secondary hydrocarbon miscible flood HCMF.
The secondary hydrocarbon miscible flood extension was initiated due to the success of the waterflood, experience from other operated vertical HCMF’s, and available royalty incentives. Design of the multi-contact miscible solvent slug and strategic production plans are described and compared to actual performance.
Better than expected performance of the secondary miscible flood lead to the further development of a full field tertiary miscible flood. The tertiary flood is described in the companion paper by K. A. Edwards and D. A. MacLean.1
The Design, Implementation, and Early Performance of the Acheson Tertiary HCMF
Authors: Edwards K. A. , MacLean D. A. 
Published: December 2007

ABSTRACT
This paper describes the design of a full-field vertical tertiary hydrocarbon miscible flood (HCMF) in the Acheson D-3A pool. Subsequent design changes based on secondary HCMF performance, and early production history are presented. Monitoring and operation of the HCMF are also discussed.
The Acheson tertiary HCMF is unique in that there was no secondary production component in most of the tertiary miscible flood area. Two years of solvent injection, beginning in late 1990, were required to mobilize waterflood residual oil and generate an oil bank before production could begin. The original design, based on early performance from the secondary HCMF, called for a 10% hydrocarbon pore volume (HCPV) solvent slug followed by chase gas. However, later secondary HCMF performance indicated these design criteria were too optimistic.
Estimates suggested that an increased solvent slug size of 16–45% HCPV would be required. However, such a large slug requirement could jeopardize the economics of the flood. In order to minimize the size of solvent bank required, a solvent cycling strategy was adopted in which a solvent composed almost entirely of ethanes plus is injected into the solvent bank to replace and supplement produced solvent.
Two simulation models were used to design the cycling scheme, and develop the operating and monitoring strategies. One was a full-field cross-sectional model, and the other a detailed geostatistical cross-sectional model. They proved invaluable in understanding the mechanics of the displacement process and designing the solvent cycling scheme.
Horizontal Well Evaluation After 12 Years
Authors: Coffin Philippe 
Published: December 2007

Abstract
The paper presents a survey of 82 horizontal wells drilled between 1980 and 1992.
The survey includes 50 wells operated by ElfAquitaine during this period, plus 32 wells operated by partners. It covers more than 20 reservoirs in 13 different countries, onshore and offshore.
From the data base generated by the survey, statistical analyses are performed on the type of application, reservoir data, drilling and completion methods. The results are discussed.
Production performance and well costs are evaluated and compared to those of conventional wells.
Finally, the paper addresses successes and failures, and their causes. A rate of success is evaluated.
WAG Process Optimization in the Rangely CO2 Miscible Flood
Authors: Attanucci Vincent , Aslesen K. S. , Hejl K. A. , Wright C. A. 
Published: December 2007

Abstract
A miscible CO2 project was initiated in the Rangely Weber Sand Unit in northwest Colorado in 1986. Over the past seven years, the project has expanded areally to include 80% of the Unit, and substantial investments have been completed in injection, production and gas recompression facilities. As the project matures, emphasis has shifted from adding new CO2 injection patterns to management of CO2 injection, with goals of maximizing recovery and reducing operating costs. Optimization of the Water-Alternating-Gas (WAG) injection process is an important part of this effort.
Our initial injection strategy was based on reservoir simulation studies. It became apparent as the project matured that we would need to make changes in WAG processes to adapt to operational constraints and maximize pattern economics. Flood performance was optimized through further simulation and field testing of changes to CO2 slug size and WAG ratio tapering sequence. New methods for managing the WAG process based on injection pattern performance and economic triggers have been adopted. We have completed an initial comparison of predicted versus actual performance for injection patterns with tapered WAG ratios.
Simulation studies and field tests have also been completed to determine an optimum half-cycle for the WAG process in Rangely. A half cycle is defined as the amount of CO2 or water that is injected, measured in pattern hydrocarbon pore volumes, before switching to the alternate fluid. Our simulation and pilot project results have shown that decreasing the half-cycle has favorable economics. Results of the pilot have also demonstrated that production and fluid handling costs can be reduced by controlling fluctuations in gas and water production. Future plans for WAG optimization include continuation of performance monitoring to help optimize tapering strategy, and extension of the reduced half-cycle application to include simultaneous injection of CO2 and water.
Lost Hills Diatomite Simulation Study: Predicting Waterflood Performance in a Low-Permeability, Compacting Reservoir
Authors: Fast R. E. , Murer A. S. , Zambrano L. G. 
Published: December 2007

Abstract
A numerical simulation model was developed to predict waterflood performance and guide reservoir management in a low permeability, highly compactive opal-A diatomite reservoir. The 3-D model incorporates 23 reservoir layers and three rock types. Each rock type has unique, laboratory-measured compaction and relative permeability characteristics. Hydraulic fractures, dual-porosity, and dual-permeability features are incorporated. The model was validated by history matching and compared to field performance. Predicted results have been confirmed by the ongoing response to waterflooding. Reservoir description, model design, history matching, and prediction sensitivities are presented.
Measurement of Inflow Performance Parameters for Coal Seam and Devonian Shale Gas Reservoirs and Its Implication in Numerical Reservoir Simulation
Authors: King G. R. 
Published: December 2007

ABSTRACT
This paper describes potential inconsistencies between the traditional methods used to estimate inflow performance parameters for conventional gas reservoirs and the way these parameters are used in analysing coal seam and Devonian shale gas reservoirs, particularly in numerical reservoir studies. These inconsistencies arise because of the unique reservoir characteristics and mechanisms associated with unconventional gas reservoirs.
For unconventional gas reservoirs undergoing non-equilibrium (dual-porosity) desorption, inflow performance parameters measured from deliverability tests may not be appropriate for numerical reservoir simulation. This is because the static pressures used in deliverability testing are influenced by the effects of pressure depletion in the fractures (during flowing conditions) and blow-down from the rock matrix (during shut-in). Under flowing conditions, the inflow performance in numerical reservoir simulators is governed solely by the cleat (fracture) pressure of the grid block.
Consequently, if a non-equilibrium desorption formulation is used in the simulation study, then the use of inflow performance parameters derived by deliverability testing may yield erroneous results.
The inconsistencies and analysis techniques discussed in this paper are applicable for all reservoir studies involving the inflow performance from unconventional gas reservoirs (analytical or numerical), however, they are more critical for numerical studies. These techniques are believed to be useful for understanding the need for representative inflow performance parameters for unconventional gas reservoirs.
Modeling the Effect of Subseismic Faults on Gas/Oil Displacement in the Upstructure Region of the Prudhoe Bay Field, Alaska
Authors: Angert P. F. , Bevan T. G. , Heffer K. J. , Pearce A. J. 
Published: December 2007

ABSTRACT
Advances in the area of statistics / geostatistics, has allowed the estimation and subsequent object based modeling of the occurrence and spatial relationship of sub seismic faults in the upstructure area of the Prudhoe Bay Field. Statistical techniques assume that a power-law relationship can be used to determine the number of sub seismic faults of a particular length that exist within a given area.
Subsequent numerical gas / oil fluid flow simulation through realizations of this portion of the reservoir with and without sub seismic faults represented has revealed the significant impact faults with throws less than seismic resolution have on fluid flow. An analysis of individual historical / predicted well GOR performance supports the conclusions about the effect of sub seismic faults.
In the interwell region, sub seismic faults in the upstructure area of the Prudhoe Bay Field mitigate the magnitude and frequency of gas under running continuous and discontinuous shales by breaching thinner shales. This allows a path by which gas may migrate upwards toward the current GOC.
In the near wellbore region, breaching of continuous / discontinuous shales by sub seismic faults results in an increased potential for gas coning, due to a higher effective Kv/Kh ratio.
Explicit modeling of continuous / discontinuous shale distributions within the upstructure area of the Prudhoe Bay Reservoir without inclusion of the effect of sub seismic faults results in an inability of numerical fluid flow simulation to even come close to matching past historical production performance.
Techniques utilized and the methodologies described, allow the evaluation of the effect of sub seismic faults in fluvial depositional environments that can be characterized by sandstone matrix interbedded with large continuous and discontinuous shales.
Application of Variable Formation Compressibility for Improved Reservoir Analysis
Authors: Yale D. P. , Nabor G. W. , Russell J. A. , Pham H. D. , Yousef Mohamed 
Published: December 2007

Abstract
Formation compressibility has long been recognized as an important factor influencing production behavior from overpressured oil and gas reservoirs. However, formation compressibility data are not routinely collected and the use of formation compressibility in reservoir analysis and simulation is often oversimplified.
This paper discusses more accurate methods to determine formation compressibility and introduces a new method for analyzing overpressured oil and gas reservoirs which utilizes the variability of formation compressibility with declining reservoir pressure. The newly developed method departs from earlier proposed methods in the use of variable rather than fixed formation compressibility by employing a "pore volume formation volume factor", Bf, that properly integrates pore volume compressibility effects over the full pressure range of investigation. Using the new concept of Bf, the material balance equation (MBE) can be modified to include the effects of pressure dependent formation compressibility.
We find that the formation compressibility in highly overpressured unconsolidated reservoirs can be the same order of magnitude as gas compressibility and significantly higher than oil compressibility. In some types of reservoirs, an order of magnitude change in formation compressibility can occur during drawdown. We show that in many overpressured and/or unconsolidated reservoirs, proper integration of accurate formation compressibilities is important for reserve estimates, determination of drive energies, and overall reservoir development plans. For example, we find that the use of compressibility values in the MBE which are significantly lower than those which exist in the reservoir could suggest a strong water drive where one does not exist.
Critical Gas Saturation: Modeling and Sensitivity Studies
Authors: Li Xuehai , Yortsos Y. C. 
Published: December 2007

ABSTRACT
The critical gas saturation (Sgc) is an important parameter in solution gas-drive processes. Despite considerable amount of research, however, both the concept and its values in various porous media remain unclear and a cause of confusion in the literature. Based on various definitions, values as low as 1% and as high as 27% have been reported. In this paper we present an investigation on the fundamental aspects of bubble growth and the formation of critical gas saturation in porous media. A theoretical model is developed, based on which a pore network simulator is constructed. We discuss patterns and rates of growth for single and multiple gas clusters, using statistical models, such as percolation and DLA. It is shown that in porous media, gas evolution (patterns and rates) are much different than in the bulk. The critical gas saturation is studied in terms of the system parameters, notably the nucleation fraction and the pressure decline rate. Sgc is found to be increasing with the nucleation fraction and the pressure decline rate at relatively high rates, but to be independent of the latter at sufficiently small rates. A condition for this is developed. The scaling up with system size is also discussed.
Future Performance Prediction for Water Drive Gas Reservoirs
Authors: Layne M. A. , Numbere D. T. , Koederitz L. F. 
Published: December 2007

Abstract
The development and application of a Boundary Element model for the prediction of gas reservoir performance under water drive conditions is presented. The model retains the natural coupling of the gas reservoir with the aquifer and treats them as a two-region composite system. The diffusivity equation is written separately for each region and each is converted to a Boundary Integral equation. The two resulting equations ( non-linear for the gas reservoir and linear for the aquifer) are linked by the compatibility and continuity conditions on the gas/water interface boundary separating the two media. A modification of the Powell hybrid method was used to solve the final combined non-linear matrix.
Output from the model include predictions of the pressures along the reservoir aquifer interface or gas-water-contact (GWC), the average pressure in the gas reservoir, and the average aquifer pressure.
These are plotted and presented as functions of time. These plots can aid analytical predictions of gas reservoir performance using the Material Balance Method.
The model is validated by comparing its results with those using a finite difference simulator. The results show comparable accuracy with finite difference models but with less data input. This is a useful model for areally large and arbitrarily shaped systems such as reservoir/aquifer composites because it has less data requirements than conventional numerical models.
Predicted Increase in Gullfaks H2S Production Associated With Injected Sea Water -- Application of Biofilm Model
Authors: Tyrie J. J. , Ljosland E. 
Published: December 2007

Abstract
H2S was found to be Increasing in Gullfaks produced sea water. Wells supported by the same injector showed similar development indicating an association between the injector and the H2S. Statoil's biofilm model was used to history match this behaviour to set the input parameters and enable a prediction to be made for each well. Some wells will exceed the process H2S limits and solutions are discussed. Produced water re-injection was shown to be detrimental to souring reservoirs.
Conversion of a Semisubmersible Drilling Unit for Tender-Assisted and Conventional Drilling Operations
Authors: Spiers R. L. , Tranter P. H. , Burr G. R. , Unsworth M. I. 
Published: December 2007

ABSTRACT
The economics of marginal field development in the UKCS can be made much more attractive by reducing capital investment costs in drilling equipment, platform equipment, and jacket structure sizing and construction. This can be achieved through the introduction of semi-submersible Tender Assisted Drilling (TAD) techniques. The classical approach to TAD requires the use of a standard flat floating barge in support of a small jacket mounted drilling package. This technique cannot be used in the severe environmental conditions of the North Sea, but the viable alternative of using a modified semi-submersible drilling unit has been identified and more recently put into place.
An international drilling company, under contract to a major North Sea operator, has modified a Sedco 700 series design semi-submersible drilling unit (Sedco 704) to perform drilling operations in both TAD and conventional stand alone drilling mode for a UKCS development project. The planning, design, modifications, and performance tests were completed within the contract schedule and budget cost and the unit was delivered ready for platform hook-up and drilling operations in December 1992.
This paper discusses the philosophy behind the selection of the unit, the studies associated with the complicated mooring requirements, and the modifications made to allow for operations in TAD or stand alone drilling mode. Solutions to interfacing problems with the transfer of power, drilling fluids, and personnel between the unit and the jacket are also described and discussed.
Produced Brine Underground Disposal Injection Cost Model
Authors: Weller T. F. 
Published: December 2007

Abstract
Key components in the economic evaluation of either production or development prospects are the capital requirements and operating costs of a brine disposal system. Many times, emphasis and attention are given solely to the potential and resulting cash flow from production. Proper planning requires that consideration be given to producing costs. A key component of producing costs is the cost of operating a brine disposal system and the required capital investment.
Several Issues must be addressed in order to gain an understanding of the true cost of brine disposal. Generally, in the oil and gas industry, brine is disposed into SWD wells via underground injection. The cost of disposal is dictated by the depth of the disposal interval, the formation characteristics (i.e., thickness, skin, permeability, pore pressure, frac gradient, porosity, injection area), tubular sizes and the maximum allowable wellhead injection pressure. The anticipated fluid volumes to be injected into each well, well life and the number of required injection wells are critical in assessing the true cost of managing an underground injection project. Unrealistic assessments initially can result in less than desired economic consequences.
This paper is a description of an underground injection cost model that will provide the capital and operating costs and optimize those costs based on hydraulic fracture design under specified reservoir conditions.
Generally, the process to develop brine disposal operating cost include the use of 3D reservoir, fracture and economic models. Various sensitivities must then be run and the results compiled in order to property estimate capital and operating costs. This model incorporates all key parameters and sensitivity analysis is done very quickly with a minimum of input. The model has correlations for many parameters that need to be estimated or calculated utilizing conventional models. This decreases the amount of design time, data required and familiarity with sophisticated models, and allows for easier parametric analysis. The model also allows for the user to input and modify additional parameters if the data is available.
Fundamental Study Makes Improved Air Drilling Technology Possible
Authors: Adewumi M. A. , Tian Shifeng , Watson R. W. 
Published: December 2007

ABSTRACT
Because of poor understanding of the wellbore hydraulics involved in air drilling, the operating conditions are not optimal and consequently costs are higher in terms of rig time, personnel time, and equipment. Moreover, various post-drilling wellbore repair operations must often be performed to repair the damage done to the formation in the pay zone region in an improperly designed air drilling operation.
The importance of having a thorough understanding of wellbore hydraulics in air drilling can not be over-emphasized. Predictive capability of the hydraulics involved arises mainly from the intricate interactions between the wellbore, the drill string, the formation, and the particulate transport in the wellbore-drill string annulus. Lack of this understanding and the resulting lack of predictive capability leads to unexpected occurrences downhole, which at times lead to catastrophic fatality. An adequate understanding of the wellbore hydraulics will evolve into appropriate predictive capability, which can aid in the reduction of operational costs and risks involved and can help to provide optimal operation. The results of the work summarized in this paper will significantly enhance the scientific base for this highly desirable and economically attractive technology.