bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reserves Estimation and Classification Challenges in a Mature Oil Field
Authors: Zubari Hisham K. , Kumar K. 
Published: December 2007

Abstract
Estimation of hydrocarbon reserves is governed by natural, technological and economic factors. Re-estimations and reviews continue almost till the end of exploitation in many instances. Estimation of oil reserves, when a field is in its initial stages of development is a relatively easy task. The estimation will not invite critical or close scrutiny, as the oil production at that stage is far lower than the reserves calculated. However as the field matures and the cumulative oil production approaches the estimated value of reserves, the accuracy in the estimation of reserves becomes crucial and more important. Also the estimation process itself is a challenging task, in the light of uncovering geological complexities and reservoir dynamics during the development and the exploitation methods employed to produce the oil.
Bahrain field, the first discovery in the Arabian Gulf region, has been on production since 1933. It is a multi-stacked field with 16 oil and 4 gas reservoirs. Most of them are carbonate reservoirs. The nature of the fluids varies from tarry oil in the Aruma formation occurring at shallow depths to dry gas in the deep Khuff zones.
The geology of the field is complex with a large number of faults on the structure. The major oil zone Mauddud – an oil wet system - has been on gas injection from 1938. The gas injection has lead to the transfer of oil and gas into layers above and below through the faults. Though many reservoirs of the field have reached mature stage, there are some zones containing oil resources still unexploited due to the heterogeneities, complex nature of the fluid distribution, unfavorable rock-fluid characteristics, compartmentalization, thin oil rim overlain by gas and underlain by water, etc.
This paper brings out the challenges posed by the above situations while attempting to estimate and classify oil reserves.
Lessons Learned from Energy Models: Iraq's South Rumaila Case Study
Authors: Kabir C. S. , Al-Khayat N. I. , Choudhary M. K. 
Published: December 2007

Abstract
Understanding reservoir behavior is the key to reservoir management. This study shows how energy modeling with rapid material-balance techniques, followed by numerical simulations with streamlines and finite-difference methods, aided understanding of reservoir-flow behavior. South Rumaila's long and elongated Zubair reservoir experiences uneven aquifer support from the western and eastern flanks. This uneven pressure support prompted injection in the weaker eastern flank to boost reservoir energy.
We learned that aquifer influx provided nearly 95% of the reservoir's energy in its 50-year producing life, with water injection contributing less than 5% of the total energy supply. The west-to-east aquifer energy support is about 29:1, indicating the dominance of aquifer support in the west. Streamline simulations with a 663,000-cell model corroborated many of the findings learned during the material-balance phase of this study. Cursory adjustments to aquifer properties led to acceptable match with pulse-neutron capture or PNC-derived-time-lapse oil/water contact (OWC) surfaces. This global-matching approach speeded up the history-matching exercise in that performance of most wells was reproduced, without resorting to local adjustments of the cell properties. The history-matched model showed that the top layers contained the attic oil owing to lack of perforations.
Lessons learned from this study is that the material-balance work should precede any numerical flow-simulation study because it provides invaluable insights into reservoir-drive mechanisms and integrity of various input data, besides giving a rapid assessment of the reservoir's flow behavior. Credible material-balance work leaves very little room for adjustment of original hydrocarbons in place, which constitutes an excellent starting point for numerical models.
Fully Upscaled Saturation-Height Functions for Reservoir Modeling Based on Thomeerg's Method for Analyzing Capillary Pressure Measurements
Authors: Buiting J. J. M. 
Published: December 2007

Abstract
Upscaling is a long standing problem for the construction of saturation height models. Upscaling is difficult when desiring to honor and retain the information obtained from core descriptions, facies classifications and mercury injection capillary pressure (MICP) data. In Saudi Aramco MICP experiments are widely used for measuring the architecture of the rock's pore system. For the analysis of these measurements Thomeer functions are standardly used. The Thomeer parameterization proved to be very adept for handling the complexity and multimodality of carbonate pore systems. In this paper a direct and closed form solution of the upscaling problem of MICP data to arbitrary large reservoir elements has been derived for standard Thomeer functions. All statistical variations of the essential rock properties, describing the architecture of the pore-system, have been included in the formalism. The upscaled result retains the familiar form of a Thomeer function while replacing single core plug values with their statistical equivalents. One of the important consequences is that intrusion of liquids for large pieces of rock can happen at much lower capillary pressures and thus much closer to the free water levels in oil reservoirs.
A New Production Allocation Optimization Framework
Authors: Guyaguler B. , Byer T. 
Published: December 2007

Abstract
Determination of the operating conditions of a field under a set of physical system constraints (e.g. compressor limits) and engineering preferences (e.g. voidage replacement) is a primary concern for petroleum engineers. Rule-based systems have been proposed for this but the process is most suitably defined as an optimization problem. An optimization procedure utilizing Mixed Integer Linear Programming (MILP) is proposed in this study. Well rates that honour system and engineering constraints are simultaneously handled while the maximum for an objective is sought (e.g. field oil rate or cash revenue). Optimal rates for the current conditions of the field are determined. Note that this amounts to instantaneous optimization, hence cannot account for recurrent events such as water break-throughs. Nevertheless, an efficient and robust instantaneous optimizer is useful within a grander optimization scheme, within short forecast periods and also in real-time allocation situations. The proposed approach is able to efficiently handle the nonlinearities in the system by way of piece-wise linear functions. Also due to the formulation of the problem, the exact optimal solution is guaranteed to be found. Another property of the approach is that, in cases where it is not possible to simultaneously honour all the targets and limits of the system, a scheme is introduced that allows the engineer to prioritize the constraints. This prioritization scheme proves to be of great practical significance since most real cases have conflicting targets and limits, which result in optimization systems with no feasible solutions. Also a heuristic is introduced and utilized, that ensures realistic results by the elimination of mathematical artefacts (rate oscillations in time) that often arise when the reservoir contains wells with similar properties (e.g. WOR and GOR). The optimization system is applied to synthetic cases and two real field cases. The real field cases pose problems that cannot be handled by conventional rule-based systems.
Deployment of an SeROP Predictor Tool for Real-Time Bit Optimization
Authors: Guerrero Christine A. , Kull Bobbie Jo 
Published: December 2007

Abstract
Since 1965, specific energy (SE) principles have been used to predict bit performance and analyze rate of penetration (ROP) and bit efficiency(1). Factors that create drilling inefficiency include bit dull, bit balling, bottomhole balling/cleaning issues, torque/drag, and drillstring vibrations. These are often evident with high SE values. Based on these principles, Chevron has established proprietary relationships for bit-specific coefficient of sliding friction and mechanical efficiency as a function of the rock's confined compressive strength (CCS). Chevron then uses these relationships to predict reasonable and achievable ROPs with the associated bit torque for several bit types most commonly used in their global operations. The effect of mud weight, blade count, and cutter size to the coefficient of sliding friction and efficiency are considered in the ROP predictions(2). These relationships have proven to be of high value in the creation of a globally accurate drilling tool for improving overall bit performance and reducing well costs.
Applied real time, the tool identifies inefficient drilling conditions and provides operations personnel with the reliable information needed to make more informed decisions and achieve the best possible performance out of the bit that is in the hole, as well as quantify the impact of parameter changes.
This paper will present a number of global case histories showcasing Chevron's rapid deployment of the Specific Energy Rate of Penetration (SeROP) Predictor Tool to maximize its value and reduce drilling costs. These case histories used evolving strategies, which varied according to the well's complexity and the wellsite resources available. Also shown are the incremental benefits gained when bit performance prediction/selection modeling was coupled with real-time down-hole measurements. The paper also presents the limitations and increased data requirements that are required for complicated wellbore geometries.
Remedial Frac Operations in Deep Tectonic Wells: Mechanical and Operational Issues
Authors: Rylance M. , Doig T. W. , Hoff R. , Knopp S. N. 
Published: December 2007

Abstract
The Cupiagua retrograde Gas-Condensate reservoir, in the Llanos foothills of Colombia, was developed using a fast-track approach to provide production against an aggressive delivery plan. Unfortunately, an unusually severe condensate-banking effect combined with difficult perforating and drilling induced damage, meant that deliverability of the wells failed to achieve the desired levels.
This paper describes the approach that was taken to economically remediate these multiple-stacked reservoirs by the novel deployment of a through-tubing Frac-String. In addition, due to the highly tectonic regional-stresses, the final variant of this through-tubing frac-string was designed to permit surface treating pressures of up to 18,500 psi.
This solution was primarily possible due to the mono-bore completions with which the Cupiagua field had been originally developed. The frac-string was deployed through tubing with open perforations on the annulus; in addition variants, such as a slim-hole frac-string, allowed deeper zones within smaller production-liners to also be stimulated. The technology of the Frac-strings was incrementally developed over time and in this way new and more increasingly complex challenges could be undertaken without dramatically increasing the overall risk on each treatment.
More than 136 deployments of various string variants have been performed successfully; and even though annular tool clearances have been as low as 1/20" there has not been a single stuck-pipe incident to date. Throughout these operations the frac-string pressure test history has been faultless and the cumulative proppant placed during the frac treatments has amounted to more than 6,250,000 lbs.
Finally, significant production increments have also been achieved, the first well increased in productivity from ca. 8,000 bcpd to 18,000 bcpd and numerous low delivery wells were stimulated into becoming major producers. Individual case studies will be presented to support this, along with the production histories of the first 3 treatments.
Remedial treatments, of these deep tectonic wells, have been economically feasible due to the ability to deploy a frac-string through the existing completions. Variations on the actual rig-up, deployment and design have allowed economically less favourable wells to become feasible candidates. In addition, the continued field development, extension and infill drilling has also been made possible by the application of this novel approach.
Deployment of a Riserless Mud-Recovery System Offshore Sakhalin Island
Authors: Brown J. D. , Urvant V. V , Thorogood J. L. , Rolland N. L 
Published: December 2007

Abstract
A riserless mud recovery system enables dual gradient subsea drilling operations to take place with the well open at the seabed. There are no pressure containment devices at the wellhead, but as with earlier systems developed for deep water drilling [1], mud and cuttings are returned to the rig by means of a subsea pumping system, fluid recovery hose and umbilical. The system was field tested as part of the Norwegian DEMO2000 project [2]. Subsequently, it has seen operational service in a multi-well drilling campaign in the Caspian Sea.
This paper describes how the system was implemented in a remote area exploration drilling operation off Sakhalin Island. Following experience in 2004 and 2005 [3] a clear business case emerged with the underlying drivers of limited weather window, shallow gas and stringent discharge regulations. Accordingly a formal project was established and a number of critical risk reduction studies were carried out in relation to shallow gas and integrity of the return hose under high current conditions. Correct interfacing onboard the rig required careful choice of location, power supply, wellhead and remotely operated subsea vehicle. There changes were verified by means of a formal hazard and operability review. A significant part of the effort involved gaining certification of the equipment for use in the Russian Federation in parallel with the fabrication, acceptance testing, mobilisation, offshore installation and commissioning of the system. The paper concludes with a review of the operational experience from the 2006 drilling season along with the associated lessons learned and forward plan.
A Streamline-Based Model for Potentiality Prediction of Enhanced-Oil Recovery
Authors: Hou Jian , Zhang Shun-kang 
Published: December 2007

Abstract
A pseudo-three dimensional model of potentiality prediction is proposed for enhanced oil recovery based on boundary element method (BEM) and streamline method in this paper. The potential distribution of the flow through porous medium under the complicated boundary condition is solved with BEM, which overcomes the defects of traditional mirror image method. Further more, the method for tracing streamlines between injectors and producers is presented. Base on this, numerical solution can be obtained by solving the seepage problem of stream-tube with the consideration of different methods of enhanced oil recovery. In this way, the aim of dynamic prediction can be achieved. The advantage of the method in this paper lies in the fact that it can realize the dynamic calculation with different well patterns in any shape by easily considering different physicochemical phenomena with less calculating time and good stability. Based on the uniform theory basis - streamline method, different models including CO2 miscible flooding, polymer flooding, alkaline/surfactant/polymer flooding and microbial flooding are established in this paper. Polymer flooding model has been successfully applied to the EOR potential evaluation in different reservoirs of Shengli oilfield.
Development of a Dual Media Full-Field Simulation Model to Optimize Injection/Production Strategy for Two Communicating Mature Carbonate Reservoirs
Authors: Chiffoleau Yann , Shenawi Shamsuddin , Yuen Bevan , Al-Garni Saad A. , Lyngra Stig , Al-Shammari Methgal A. , Al-Shammary Turky M. 
Published: December 2007

Abstract
An advanced integrated reservoir study has been performed for a giant mature oil field in Saudi Arabia. The field is composed of two naturally fractured reservoirs that are separated by a thick non reservoir formation. Same pressures have been recorded in both reservoirs since the start-up of production. Consequently, the two reservoirs are clearly in direct hydraulic communication. The geological data support that the communication is taking place through fractures swarms (sub-seismic faults) which affect the two reservoirs. A multidisciplinary approach was used to characterize and model the location of the fracture swarms by integration of available dynamic and static data. The resulting fracture grid of the simulation model combines diffuse fractures and fracture swarms.
This paper discusses the ways to simulate these dual porosity – dual permeability (DPDP) systems that behave very differently, but still interact with each other. The lower reservoir is a tight matrix with diffuse fractures. Fracture density and capillary pressure control the oil recovery in this mixed wettability carbonate rock. Moreover, fracture swarms create reservoir anisotropy, which causes preferential fluid paths. In the upper reservoir, the matrix is very permeable with highly conductive strata. Due to the high matrix permeability, the dynamic contrast between the matrix and fracture media is low; thus, the fracture swarms only act as global permeability enhancers.
This fracture multi-scale approach enabled us to history match the 5 millions active cells model (DPDP mode). The modeling accuracy was significantly improved by better representing the physics of the fracture-controlled system. It also provided new insight into the complex interactions between the two reservoirs through fracture swarms. The production history supports that these exchanges have been controlled by pressure regimes and fluids segregation in the fracture swarms. A better understanding of these communications led to a more optimized future injection/production development strategy.
Integrating Drilling-Fluid Optimization and New Technology Improves Carbonate Reservoir Evaluation
Authors: Okuyiga Moyosore , Berrim Ahmed , Haddad Sammy , Xian ChengGang , Abu Lawi Majed , Al-Naser Jamil 
Published: December 2007

Abstract
Wireline formation testing in low permeability carbonate reservoirs of the U.A.E. has been challenging with frequent tool plugging, extended pumping time, and multiple trips out of the hole. A recent well, drilled offshore Abu Dhabi for ADMA-OPCO, penetrated the main three reservoirs and presented a rare opportunity to address these challenges. The tested intervals contain multiple thin zones, which make it difficult to predict reservoir fluid types from open-hole logs or pressure gradients alone. An extensive Downhole Fluid Analysis (DFA) program was needed for fluid types and contacts determination.
A multidisciplinary team between the operator and the service company was organized to carefully consider the challenges mentioned above, identify the source problems and recommend a solution. The solution involved the economically viable replacement of the drilling fluid with a low solid content fluid prior to the wireline formation testing operations. A new wireline formation tester technology, the Extra Large Diameter module (XLD), was also recommended to replace the dual-packer at a broad permeability range. The combination of drilling fluid displacement, XLD utilization and the addition of two pumps proved to be major factors in reducing the overall job duration, rig time, and smoothly achieving the required objectives.
As the results, a record job including 27 DFA stations (16 with samples), 2 mini-frac stations and in access of 90 pressure points were achieved. The DFA and samples provided significant answers and clues to a broad range of reservoir issues including compartmentalization, fluid compositional variation, the unexpected identification of oil, oil reserve assessment, and gas compositional analysis to understand its origin and potential contact migration. The wireline formation testing results have added direct values to reservoir evaluation and development. In this work, a best operating practice for similar reservoirs is demonstrated.
Topdrive Casing Running and Drilling Tools Reduce Well-Construction Costs and Increase Safety
Authors: Shahin Nazir , Cummins Tracy 
Published: December 2007

Abstract
A new portfolio of remotely operated casing running and casing drilling tools that connect to the rig's top drive and use the top drive's rotational power, hoisting and circulation capabilities for improved casing running operations. The value is increased safety and efficiency compared to conventional running operations, plus the ability to instantly push down or reciprocate while rotating and circulating, helping to get strings to bottom.
Applications include normal casing installation in pre-drilled wells on most rigs with a top drive system, and extended reach, deviated, and troublesome wells. Additional application includes casing drilling technology where the entire well bore can be drilled with the casing string; eliminating the need for drill pipe and bottom hole assemblies.
The new system combines several conventional casing handling tools into one:
Power Tong Main Hoisting Elevator Single Joint Elevator Fill-up and Circulation Tool Weight Compensator Link Tilt (Stabber) Safety Interlock System
Lab and field test results have proven that the new technology provides:
Greater casing running efficiency Increased safety by reduction of personnel and remote operation.
Step change in technology will allow oil & gas operators to increase drilling performance and reduce well construction costs.
Multiobjective Optimization With Application to Model Validation and Uncertainty Quantification
Authors: Schulze-Riegert Ralf , Krosche Markus , Fahimuddin Abul , Ghedan Shawket 
Published: December 2007

Abstract
History Matching in Reservoir Simulation, well location and production optimization etc. is generally a multi-objective optimization problem. The problem statement of history matching for a realistic field case includes many field and well measurements in time and type, e.g. pressure measurements, fluid rates, events such as water and gas break-throughs, etc. Uncertainty parameters modified as part of the history matching process have varying impact on the improvement of the match criteria. Competing match criteria often reduce the likelihood of finding an acceptable history match. It is an engineering challenge in manual history matching processes to identify competing objectives and to implement the changes required in the simulation model.
In production optimization or scenario optimization the focus on one key optimization criterion such as NPV limits the identification of alternatives and potential opportunities, since multiple objectives are summarized in a predefined global objective formulation. Previous works primarily focus on a specific optimization method. Few works actually concentrate on the objective formulation and multi-objective optimization schemes have not yet been applied to reservoir simulations.
This paper presents a multi-objective optimization approach applicable to reservoir simulation. It addresses the problem of multi-objective criteria in a history matching study and presents analysis techniques identifying competing match criteria. A Pareto-Optimizer is discussed and the implementation of that multi-objective optimization scheme is applied to a case study. Results and consequences for the uncertainty quantification are presented.