bluuebunny/crossref_metadata_2025_split huggingface dataset:
Control of Fluid Injection into a Low-Permeability Rock - 1. Hydrofracture Growth
Authors: Patzek Tad W. , Silin Dmitriy B. 
Published: December 2007

Abstract
This paper deals with growth of injection hydrofractures in transient linear flow in a low permeability, soft rock. Seventeen waterflood injectors in Section 12 of the Middle Belridge diatomite, three steam injectors in Section 29 of the South Beiridge diatomite, as well as forty four injectors in the Lost Hills I waterflood have been analyzed. The field data show that cumulative injection of water or steam scales with time to the power of 1, rather than V2 predicted from the theory of linear transient flow. In other words, at constant injection pressure, injection rate is remarkably constant. Therefore, either the injection hydrofractures grow with time, or the formation permeability increases with time, or both. A simple mass balance of hydrofracture growth during fluid injection, attributed to Carter, is corrected, extended to the case of variable injection pressure, and presented in a simplified form. The growth of fracture area at constant injection rate is expressed in terms of two easily measured field parameters, the early "injection slope" in linear transient flow, and the average injection rate. Carter's fracture growth rate is further halved to account for the reservoir layer homogeneity parallel and perpendicular to the hydrofracture plane. The Carter theory predictions are then compared with the growth rate of hydrofracture area calculated independently for two steam injectors in Section 29. There is remarkable agreement between the modified Carter theory predictions and the independently estimated rates of growth of these two hydrofractures. We show that fluid injection above a reasonable minimum rate must lead to hydrofracture extension if injection pressure is bounded from above. Ultimately, fracture growth is inevitable, regardless of mechanical design of injection wells and injection policy. We also show that water injection leads to less severe formation damage and fracture extension than steam. By analyzing the thermal and pore stresses, we demonstrate that steam injection may lead to the creation of horizontal fractures, vertical fracture extension, and reservoir damage. Better control of steam injection is, therefore, a must. We address the optimal injection control strategy in Part 2 of this paper.
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Optimization of Borate-Based Gels Used for Wellbore Diversion During Well
Authors: Al-Anazi H.A. , Nasr-El-Din H.A. 
Published: December 2007

Abstract
Borate-based gels are commonly used as fracture fluids. However, they can be used during well stimulation to divert the acid into the target zones only. The gelling system examined consisted of guar gum or its derivatives, a suspending polymer, a pH elevator, a cross-linker, and a chemical breaker.
Several gelling formulas were screened in the lab. Boron or zirconium was used as the cross-linker. The gelation time was measured as a function of temperature and gel composition. The effects of salinity and hardness of the mixing water on gel properties were studied. The apparent viscosity of the gelling solution was measured as a function of shear rate. Because the gel will be in contact with the acid, the rate of gel degradation by the acid was examined in detail.
The results indicated that the gelation time decreased as the temperature was increased. The effect of temperature on the gelation time can be predicted using an Arrhenius-type equation. The gelation time was found be a function of initial pH, cross-linker concentration, water salinity and hardness.
Acids (15 wt% HCl) reacted with the gel and formed a solid residue (brown particles). The amount of this residue was measured for various gels. A new technique was developed to determine the rate of gel degradation during field treatments.
A temporary gel was used on a horizontal water injector to block the open hole, and acidize the newly perforated interval only. The first treatment failed due to premature setting of the gelling solution inside the coiled tubing. Lab results indicated that the fast setting of the gelling solution was due to the presence of acidic contaminants in the mixing tank from a previous acid job. These contaminants lowered the pH of the gelling solution, and caused premature setting of the gelling solution. It was also found that a brine different from the field mixing water was used to measure the gelation time. The gelation time using the field mixing water was found to be less than that measured using the lab water by a factor of 6.
Several modifications were introduced to the gelling system and its field application was modified to avoid similar problems. The second treatment was successfully applied in the field, where the injection rate increased by a factor of 1.5. Measuring the concentration of boron in the acid returns confirmed that the acid broke the gel. Based on extensive lab/field work, guidelines to use the borate-based gels for zone isolation during well stimulation were specified.
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Integrated Asset Management: Work Process and Data Flow Models
Authors: Janele P. T. , Galvin T. J. , Kisucky M. J. 
Published: December 2007

Abstract
Reservoir characterization and flow prediction modeling form the fundamental basis of modern integrated Asset Management. As our oil industry evolves, increasingly sophisticated component technologies are being developed and applied in support of these characterization and modeling objectives. The oil industry is developing and embracing these new component technologies at a stunning pace - sometimes without full knowledge as to how each component might be consolidated into an overall solution to address real business issues.
Forging through the maze of available technologies to identify a process which will address a specific business question is a challenge that requires several insights: an understanding of the business objective and risk, an understanding of specific details as to what each technology offers and, an understanding of how each technology can be linked to form an overall solution. This is a complex quest which often results in uncertainty within both company management and employees who are unclear as to how any individual technology will "pay out" or how a particular subprocess will be used as part of a whole to "make a difference".
During ongoing efforts to evaluate new reservoir modeling technologies at Caltex, a team of Caltex specialists developed a combination work process/data flow model for reservoir modeling and characterization. The work/data process model definitions are expressed in the form of Reservoir Modeling Process (RMP) maps. These maps can be used to understand and define the overall objectives of an integrated team effort and accordingly allocate resources and project deliverables for Reservoir Characterization and Flow Modeling.
The RMP process maps are scaleable in that various degrees of sophistication, and commensurate business risk-reduction, can be implemented. Examples of RMP application and scalability are offered from the historic use within Caltex CPI Indonesia. Current limitations and future evolution of the RMP process maps is also discussed.
Evolution of Reservoir Management Techniques: From Independent Methods to an Integrated Methodology. Impact on Petroleum Engineering Curriculum, Graduate Teaching and Competitive Advantage of Oil Companies
Authors: Gringarten Alain C. 
Published: December 2007

Abstract
The reservoir management process integrates the following steps: (1) acquisition of data; (2) interpretation of each data type to obtain an interpretation model for the data; (3) integration of all available data interpretation models into a reservoir model; (4) calculation of the reservoir model behaviour with a reservoir simulator; (5) calibration of the reservoir simulator by history matching production data; (6) coupling the reservoir simulator with well and surface facility simulators; and (7) using the coupled simulators to calculate reserves and predict production for various development scenarios. This new concept in reservoir management has evolved in parallel with the re-organisation of oil companies into multi-disciplinary asset teams. These changes, however, have yet to reach most universities, which still teach each petroleum discipline as a separate subject, mainly because the various skills needed sit in separate departments. These historical barriers must be dismantled in order to give students the required understanding of (1) the fundamental concepts of reservoir characterisation, reservoir modelling, reservoir simulation, and field management; (2) the links between the various types of data; and (3) the processes for integrating and processing all available information. Another consequence of the new reservoir management methodology, coupled with the availability of commercial software enabling that methodology, is that results of reservoir management will become more predictable: given the same information, different teams applying the same methodology will reach the same conclusions, thus reducing greatly the advantage of technical knowledge in competitive situations.
Improving Profitability Through The Use of Dual and Quad Lateral Wells
Authors: Permadi P. , Wibowo W. , Sukotjo R. , Arsegianto _ 
Published: December 2007

Abstract
Among multilateral well systems that can be drilled using today'stechnology, more than thirty dual and quad lateral wells have been successfully implemented in an oil field. The advantage gained over single lateral wells is an increased reservoir access per well drilled. There are some investigations dealing with inflow performance and economic evaluation of multilateral wells, excluding dual and quad laterals. Therefore, further reservoir engineering and economic studies should be conducted to evaluate the potential of these dual and quad well systems for improving the profitability of reservoirs.
The objectives of the present work are to study the effect of reservoir characteristics on the production performance of a dual and a quad laterals and to evaluate the economic attractiveness when compared with a single lateralwell. Based on the performance prediction model used and the economic evaluation, results obtained show that the use of such multilateral wells would be economically more attractive for reservoirs with low-to-medium permeability. Also found, on the basis of the comparison made here, that the economic benefits are influenced as well by the magnitudes of reservoir anisotropy, the lateral holes placement, and producing rate.
Overall, from a reservoir management point of view, the results demonstrate the importance of adequate reservoir characterization and the production strategy in the applications. P. 53
Total Asset Management Strategy for the McKee Field, New Zealand
Authors: Adams M.R. , Stoltz L.R. , Wadsley A.W. 
Published: December 2007

Abstract
The McKee Field, onshore New Zealand, was brought to commercial production during 1984 at 5000 BOPD. Production peaked at 12,000 BOPD in 1989 and was followed by a rapid decline over the next three years to 6000 BOPD at the end of 1992. At this time it was recognized that a proactive field management strategy was required in order to minimize any further decline in field production rates as the "Produce Out - Proven Developed" production forecast showed a continuous production decline. Six key areas of revenue enhancement were identified as implementation of waterflooding in McKee Central, aggressive appraisal drilling, production optimization, exploration in proximal horizons, operating expenditure reductions, and facilities/infrastructure issues. Twenty-eight activities were resourced with a target of sustaining production rates to the year 2000 and increasing remaining reserves from 8 MMbbl (as at 1993) to 21 MMbbl. The look-back analysis presented here describes this integrated approach to reservoir management and illustrates how it continues to meet its production and reserve targets despite unanticipated reservoir complexity.
P. 77
Optimising Multi-Field Developments Under Uncertainty
Authors: McGill Colin , Goodwin S. P. , MacGowan D. , Aissaoui A. , Riddiford F. A. , Standish I. G. 
Published: December 2007

Abstract
Subsurface staff have tried to include uncertainties in their predictions for some years (e.g. Smith, Hendry and Crowther1). Unfortunately, these are not normally carried through to the development design because of the time required to engineer all the possible solutions. This paper describes a systematic process for incorporating the uncertainty, using the optimisation tool described by MacGowan and Goodwin2.
In this method, optimum facilities are designed for several hundred reservoir configurations. These can be analysed to show which of the sub-surface uncertainties are responsible for major changes to the development. In turn, this information can be used to shape any proposed appraisal programme.
The sub-surface representation adopted by MacGowan and Goodwin is described in more detail. It is shown that the representation produces profiles which are in excellent agreement with profiles generated through full simulation. Given the level of reserve uncertainties, it should be possible to derive an adequate sub-surface representation for any other reservoir process, not just depletion of dry gas.
These ideas have been applied to the proposed District 3 development in the Algerian Sahara. The results have influenced the exploration and appraisal programme. In addition, they have provided tremendous insight into how uncertainty will affect the development.
Worldwide Fiscal Systems: How are Abandonment Costs Treated
Authors: Pittard A. J. , Davitt C. P. 
Published: December 2007

Abstract
The costs of the abandonment of a field development depend on the geographical location of the structures and the number of platforms for each field, the water depth, topside weight, jacket weight, type of structure, proximity to shore, availability of equipment and the level of removal required. Thus, the overall cost of removing existing platforms is difficult to predict but is estimated to be between US$29 to US$40 billion. Both government and operator's alike have a concern that abandonment costs are so high. But how are governments addressing these cost issues?
Firstly, it must be realised that governments hands are tied in many respects with regards to decommissioning, as they are locked into complete removal of obsolete platforms (and the high costs associated with this option) in water depths less than 75 metres due to the International Maritime Organisation (IMO) guidelines, the 1958 Geneva Convention on the Continental Shelf and the 1982 U.N. Convention of the law of the sea. Platforms in deeper water do have removal options for instance, partial removal, topple in place, rigs to reefs or leave in place. Each option has advantages and disadvantages. In all cases however decommissioning will take place and the costs will be high especially in the North Sea.
Decommissioning costs do not increase oil production, in fact revenue decreases at this stage in the production life cycle. Therefore to safe guard the environment and reduce the cost burden to the operators and in Production Sharing Contract regime countries to the government themselves, governments must introduce fiscal relief regulations for abandonment costs.
Of the 135 countries with fiscal terms available for this paper, approximately 34 countries had fiscal relief clauses.
This paper will discuss the abandonment fiscal clauses and present a hypothetical model which will illustrate the best fiscal relief options for the countries which presently have no fiscal treatment of abandonment costs.
Unlocking Development Potential of a Complex Faulted Marginal Oil Field, Offshore Sarawak: Integrated Field Study
Authors: Soo D. K. Y. , Hartemink M. , Kuud T. 
Published: December 2007

Abstract
This paper describes an integrated approach of building subsurface models for a complex, faulted marginal oil field in the Balingian acreage operated by Sarawak Shell. For the field described in this paper, the modelling highlights that sand development, fault compartmentalisation and internal shale baffles are the foremost important modelling parameters that have significant impact on the production. The impact of subsurface uncertainties has been quantified in terms of production using proprietary reservoir modelling software. The quantification of the impact of associated uncertainties defines the requirements for a surface structure and allows evaluation of the value of investments that are aimed at reducing the uncertainties.
Facility Risk Assessment and Risk Management in Offshore Oil & Gas Industry
Authors: Harmony Kunu 
Published: December 2007

Abstract
This program is operational in Chevron Nigeria Limited and was introduced as a framework for integrating risk assessment within a risk management system. Also, the risk assessment program was developed to provide a process for rapid screening of risk in order to focus attention on risk levels that need to be eliminated or minimized. The article examines the principles and techniques of risk assessment and risk management, and it illustrates their applications. It also describes how these techniques are used to prioritize decisions in preparing an effective ranking of risks within Chevron Nigeria offshore facilities. Risk assessment flowcharts, hazard identification, and risk assessment checklist were generated as a rapid guide to evaluation of the level of risks and to decide which risks would need more detailed analysis. The hazard identification has the following parameters as areas of concern Viz.: - Hazardous substances, Mechanical, Radiation, Electrical, Work Environment and Work Activities Hazards. The risk assessment checklist includes details safe condition and working mechanism of Pumps, Instrumentation, Pressure vessel, Storage tanks, Fired heaters, Exchangers, Emergency Response Program, Facility Layout/Sitting etc. P. 111
Advances in Field Data Capturing to Optimize Asset Team Reservoir Development Decision Process
Authors: Dassen Jos 
Published: December 2007

Abstract
Historically, one of the more time wasting procedures within asset teams in oil companies have been the reporting, duplication and filing of data which is generated in field locations. The workflow typically in use will create many duplicates of data before it finally finds its way to the end destination.
With the advances in communication, networking and database technology better solutions are available. We will propose a solution in which data is entered into a computer only once, at the field location, and then finds its way to the corporate database. Facilities and procedures need to be created to allow for quality control and data correction before data reaches the final destination.
3-D Reservoir Modelling of the Sirikit West Field, Phitsanulok Basin, Thailand
Authors: Ainsworth R. B. , Sankosik H. 
Published: December 2007

Abstract
The Sirikit West Oil Field lies within the Phitsanulok Basin of Central Thailand. It is a satellite of the main Sirikit accumulation. Within the field, the Lan Krabu Formation represents the main reservoir interval. It is interpreted as fluvio-lacustrine in origin. The three major reservoir sub-members (D, K1 and K2) are subdivided into 10 to 15 m thick parasequences bounded vertically by minor flooding surfaces. Each parasequence represents a progradational phase of mouthbar development which is terminated by a flooding event. A typical parasequence consists of facies progressing from open lacustrine claystone to delta front including mouthbars and channel sands, to floodplain sands and shales. Compared to the Main Sirikit Field, the same stratigraphic intervals in Sirikit West are up to three times thicker. This indicates a strong element of differential subsidence across the major bounding fault between the two fields.
The depositional and sequence stratigraphic models for the area were used as a basis for generating 3-D geological and property models. 3-D modelling was undertaken to determine reservoir architecture and reservoir property trends prior to a new phase of field development. The Shell proprietary correlation software package GEOLOGIX and 3D modelling package MONARCH were utilised to enable rapid evaluation of a range of geological and petrophysical scenarios. For example, differing correlation scenarios reflecting geological uncertainties such as reservoir continuity were generated using GEOLOGIX and rapidly screened in MONARCH. The 3-D models were used for volumetric calculations, well planning, static connectivity analyses of proposed wells and as the input for dynamic flow modelling.
Upscaling of the 3-D geological models was undertaken using REDUCE and dynamic reservoir simulation was performed using the MoReS simulator. History matching of the two geological models carried forward to the simulator suggested that the high reservoir continuity scenario is the most readily matched. The dynamic model is being used as a general reservoir management tool for forecasting, well planning, and for analysing further development options. Results indicate potential for further development and appraisal drilling of up to ten new wells to fully develop the field and achieve optimal oil recovery.
EOS Simulation and GRNN Modeling of the CVD Behavior of Retrograde-Gas Condensate Reservoirs
Authors: Elsharkawy Adel M. , Foda Salah G. 
Published: December 2007

Abstract
Currently, two approaches are being used to predict the changes in retrograde gas condensate composition and estimate the pressure depletion behavior of gas condensate reservoirs. The first approach uses the equation of states whereas the second uses empirical correlations. Equations of states (EOS) are poor predictive tools for complex hydrocarbon systems. The EOS needs adjustment against phase behavior data of reservoir fluid of known composition. The empirical correlation does not involve numerous numerical computations but their accuracy is limited.
This study presents two general regression neural network (GRNN) models. The first model, GRNNM1 is developed to predict dew point pressure and gas compressibility at dew point using initial composition of numerous samples while the second model. GRNNM2, is developed to predict the changes in well stream effluent composition at any stages of pressure depletion. GRNNM2 can also be used to determine the initial reservoir fluid composition using dew point pressure gas compressibility at dew point and reservoir temperature. These models are based on analysis of 142 sample of laboratory studies of constant volume depletion (CVD) for gas condensate systems forming a total of 1082 depletion stages. The data base represents a wide range of gas condensate systems obtained worldwide.
The performance of the GRNN models has been compared to simulation results of the equation of state. The study shows that the proposed general regression neural network models are accurate, valid and reliable. These models can be used to forecast CVD data needed for many reservoir engineering calculations in case laboratory data is unavailable. The GRNN models save computer time involved in EOS calculations. The study also shows that once these models are properly trained they can be used to cut expenses of frequent sampling and laborious experimental CVD tests required for gas condensate reservoirs.
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