bluuebunny/crossref_metadata_2025_split huggingface dataset:
IOR Strategies in Brownfields of Mehsana Asset, North Cambay Basin, India
Authors: Pratap V. , Sood R. K. , Ram Binay 
Published: December 2007

Abstract
Mehsana tectonic block in North Cambay Basin is a fairly well explored, productive block where oil is both heavy and light. The block is now in a mature stage of exploitation associated with EOR techniques. Since oil production commenced in 1968–69 with a meagre 26 tons/day, the main fields have been developed through well planned development schemes. The recovery factor is intimately associated with reservoir heterogeneities, manifestation of environments of deposition, drive mechanism, fluid properties, pool size and depth of occurrence. These inherent characteristics are further influenced by reservoir management practices. The decline in oil production of the nineties was arrested and consistent growth since 1999 has been effected through efficient reservoir management practices accentuated by commencement of induction of technology.
IOR strategies with the objective of enhancing (i) Recovery and (ii) Production; are in vogue in the asset and began with revisiting the field geological and reservoir models. Strategies include:(a)Infill drilling recovery mechanism;(b)Initiation/Modification of water injection;(c) Enhanced oil recovery through Insitu combustion technique in heavy oil fields (d) High technology drilling like horizontal, high-angle-high drift wells and ultra-short radius drain holes and (e) By passed reserves identification and recovery methods like microbial methods addressing recovery enhancement. Production sustenance and enhancement through (a) Artificial Lift optimisation (b) Massive hydraulic fracturing (c) Well bore chemical stimulation in heavy oil fields and paraffin intervention in light oilfields(d) Flue gas utilization (e) Unique flue gas shut off in heavy oil belt (f) Improved sand control measures and (g) Improved sick well treatment are in place. The results from these schemes in terms of incremental oil are encouraging and have helped increase oil production marking a paradigm shift from earlier practices. Plans are afoot to foster improved production growth rate to increase ultimate recovery in tune with the newly set standards and accelerate brownfield development.
New Era of History Matching and Probabilistic Forecasting—A Case Study
Authors: Selberg S. , Ludvigsen B. E. , Diab A. , Harneshaug T. 
Published: December 2007

Abstract
This paper presents a case study using optimization technology to improve the reliability of reservoir simulation models. Global optimization techniques have been applied to assist the history matching (HM) performed. Evolutionary Algorithms and deterministic optimization schemes are integrated into a workflow controlling a large number of parallel reservoir simulations. Results are analyzed and compared to traditional HM to identify the potential added value and increased efficiency. Focus is given to the reservoir engineer who is in full control over the optimization process and interacts frequently as he/she acquires more information and improved understanding of subsurface uncertainties.
The case study demonstrates the benefit and added value of utilizing a computer assisted HM workflow. Pitfalls of using a traditional workflow are illustrated.
The paper focuses on a gas condensate reservoir where the most important well had proven to be difficult to match using a traditional manual HM approach. The sensitivities of a large number of input parameters were investigated, and an optimization scheme was set up in order to generate alternative HM realizations of the simulation model.
Alternative models were generated using a wide variety of input parameter combinations. The entire study was conducted over a two week period, where approximately 7000 full field reservoir simulations were run. A large number of simulation models were matched within the uncertainty of the observed data, and these acceptable matches gave a wide range of recoverable reserves from the field. The first match that was found proved to be outside of the initial uncertainty range, clearly verifying the need for more than one HM model to cover the uncertainty found in most producing reservoirs. This illustrates the non-uniqueness of simulation models and the danger of relying on one deterministic model.
Experimental Investigations and Findings on Deep-Well Drill-Collar Failures To Improve Drilling Downtime in Teikoku Oil Co.
Authors: Ikeda Shoichi , Tsuruta Makoto 
Published: December 2007

Abstract
Teikoku Oil Company has experienced frequent and continuous drill collar failures on drill collar connections in deep wells, causing significant expense and inefficiency. Investigations about drill collar connection failure have included metallurgy, corrosion and stress analyses to elucidate the cause of failure happened on many of the drill collars.
Several metallurgical inspections reveled that all failed drill collars were produced under proper quality control. Sulfide stress corrosion cracking and hydrogen brittle wear were also considered, but any evidence was not detected.
Although stress analyses on connections both of pins and boxes were done, the values of triaxial stress showed that all failed drill collar have been used under the normal stress conditions. Both of bending stresses ratio and stiffness stresses was satisfied API RP7G respectively.
The remaining considerable cause of failure was fatigue failure. Teikoku Oil Company carried out a number of drill collar failures reviews on each size of drill collar, reviewing a significant number of wells.
The result of investigations showed that total drilling revolutions of drill collar till failure were very similar numbers. After these investigations, standards for the maximum total drilling revolutions of drill collar to prevent fatigue failure were decided for each size of drill collar. After the critical total revolutions, all drill collars used for drilling were sent to the maintenance shop for magnetic particle test.
Teikoku found that even though magnetic particle test was done, drill collar failure still occurred. Once establishing the critical total drilling revolutions for drill collars, drill collar failure significantly decreased. The company continues to perform magnetic particle tests by drilling crews at rig site for cost saving without any problem.
Achieving the Vision in the Harweel Cluster, South Oman
Authors: O'Dell M. , Soek H. , van Rossem S. 
Published: December 2007

Abstract
With high GOR and sour gas in South Oman, re-injection schemes were considered for the recently discovered reservoirs of the Harweel Cluster in South Oman. With the light oil and very high pressure, re-injected associated gas is nearly miscible with the reservoir oils. A program of study was planned to coincide with further appraisal and bringing some of the reservoirs onto production. After five years of study and simultaneously three years of development and two years of production from a "Phase 1" project, a Phase 2 production and miscible gas injection development has been approved by shareholders and has started. The Phase 2 development is one of the largest petroleum development projects ever undertaken in Oman.
This paper describes the strategies employed by the team responsible for developing the reservoirs of the Harweel Cluster. The original vision has been bolstered by substantial near field discoveries during the last five years. The appraisal challenges, the emerging study results, and reservoir pressure and production performance have required only minor adjustment to the original development concept.
The Effect of Fixed-Cutter Bit Design Features on the Steerability and Field Performance of a Point-the-Bit Rotary-Steerable System
Authors: Peach S. , Stroud D. , Barton S. , Lockley R. 
Published: December 2007

Abstract
This paper describes how extensive testing has allowed the determination of a link between cutting structure geometry, gauge pad configuration, and achievable hole curvature or steerability. For a specific point-the-bit system, the tests have shown that steerability of the bit is not substantially dependent upon the cutting structure geometry; rather, the nature and extent of gauge pad features are crucial to the directional response of the system. Gauge pad bearing efficiency must be high while simultaneously allowing the cutting structure to tilt as directed by the rotary-steerable system (RSS).
The several case histories presented, from operations in the North Sea and offshore Indonesia, verify the results of laboratory tests regarding the relationship between design features of fixed cutter bits and steerability of a point-the-bit RSS. Furthermore, these case histories demonstrate that a point-the-bit RSS, together with an optimized bit design, can lead to improved drilling efficiency in providing good directional response, high rates of penetration (ROP), excellent-quality wellbore smoothness, improved loggingwhile-drilling (LWD) log response, and ease of completion.
Lessons Learned and Guidelines for Matrix Acidizing With Viscoelastic Surfactant Diversion in Carbonate Formations
Authors: Nasr-El-Din H. A. , Chesson J. B. , Cawiezel K. E. , Devine C. S. 
Published: December 2007

Abstract
To conventionally drill, complete and produce horizontal and multilateral wells with zero skin is not an easy undertaking. Much attention has been given to "best oil field practices" in both drilling and production processes, but the reality is that formation damage will often have to be addressed sometime during the life time of the well.
Formation damage due to drilling and scale formation is common problem in carbonate reservoirs that can be re-mediated using chemical means. The success of any treatment however, requires a complete understanding of the problem and a solution that will address the majority of the damage. The solution evolves with time and experience. Extended reach intervals with variable permeability complicate the process. Reservoir and fluid characteristics, cleanup fluid chemistry, and operational considerations must always be considered.
The acidizing experience and an improved understanding of how to effectively treat long and heterogeneous intervals in carbonate formations is rapidly evolving in Saudi Arabia. Water injectors, oil producers and wastewater disposal wells have been treated and are reviewed in this study. These wells have different configurations including: vertical, horizontal, extended reach, and multilateral with open hole and cased completions. Several acid placement and diversion techniques have been applied and a specialized treatment package was developed based on the latest coiled tubing and chemical diversion technologies. Laboratory studies, lessons learned and specific design guidelines from both successful and less than expected well treatments are highlighted in this work.
Acid Fracturing of Deep Gas Wells Using a Surfactant-Based Acid: Long-Term Effects on Gas Production Rate
Authors: Nasr-El-Din H. A. , Al-Driweesh S. , Bartko K. , Al-Ghadban H. , Ramanathan V. , Kelkar S. , Samuel M. 
Published: December 2007

Abstract
The deep, tight carbonate formations in Saudi Arabia are ideally suited for acid fracturing treatments. Various types of acids such as regular, in-situ gelled, and emulsified acids, have been used in order to achieve optimum fracture length and conductivity. Acids used for these treatments were based on 28 wt% HCl. A mixture of 15 wt% HCl and 9 wt% formic acid was used in wells completed with super Cr-13 tubulars. A high pH borate gel was pumped in stages to reduce leak-off and maintain the bottomhole pressure at values greater than the fracturing pressure of the formation.
A new generation of viscoelastic surfactant-based acid was implemented in the field. A short term production evaluation based on the initial production (post flowback) from these wells could not clearly distinguish between the benefits obtained from the viscoelastic diverting acid versus the in-situ gelled acid.1 However, the wells treated with viscoelastic surfactant based acid did clean out in a shorter period of time.
The main objective of this study was to compare the "long term" production results obtained from five wells treated with the surfactant-based acid with off-set wells treated with in-situ gelled acids. This paper provides for the first time long term production data evaluation following acid fracturing using surfactant-based acids. It also compares the performance of two main acid systems based on field data.
The evaluation of acid fracturing treatments with in-situ gelled acid systems and surfactant-based acid systems suggest that there was no significant variation in the design and the execution of both the viscoelastic and in-situ gelled acid treatments. Among the 5 wells treated with surfactant-based acid, 4 of them showed better long-term production performance over a 2-3 year period compared to their offset wells. In the short-term (nearly 3 months production), 2 wells treated with viscoelastic acid showed no difference in production performance compared to their offset wells.
Gas Condensate Wellbore Modeling Using a Fundamental Approach
Authors: Sadegh A. A. , Zaghloul J. S. , Adewumi M. A. 
Published: December 2007

Abstract
Multiphase flow in the wellbore poses a challenge for production engineers since characterization of prevailing flow regime determines the appropriate pressure drop calculation method. The problem is further complicated when the flowing fluid undergoes phase changes. The key objective was to develop a wellbore flow model based on sound physical principles, incorporating current hydrodynamic and thermodynamic methods.
The model developed comprises a flow pattern detection routine, hydrodynamic model, and an equation-of-state-based phase behavior package. The model was extensively tested with 30 field cases, proving to accurately predict pressure drop for single and two-phase (gas/condensate) flow giving an average absolute error of 6.3%.
Deconvolution of Multiwell Test Data
Authors: Levitan M. M. 
Published: December 2007

Abstract
The deconvolution analysis technique that evolved with development of the deconvolution algorithms by von Schroeter et al.1 and Levitan et al.2, 3 became a useful addition to the suite of techniques used in well test analysis. This deconvolution algorithm, however, is limited to the pressure and rate data that originate from a single active well on the structure. It is ideally suited for analysis of the data from exploration and appraisal well tests. The above mentioned deconvolution algorithm can not be used with the data that are acquired during startup and early field development that normally involve several producing wells.
The paper describes a generalization of deconvolution to multi-well pressure and rate data. Several approaches and ideas for multi-well deconvolution are investigated and evaluated. The paper presents the results of this investigation and demonstrates performance of the deconvolution algorithm on synthetic multi-well test data.
Errors Introduced by Multiphase Flow Correlations on Production Analysis
Authors: Cox S. A. , Sutton R. P. , Blasingame T. A. 
Published: December 2007

Abstract
First and foremost, production analysis techniques require accurate rate and bottomhole pressure histories. In most cases the pressure history of the well is not measured directly at the bottomhole condition, but is calculated from surface measurements by the use of single or multiphase flow correlations. In some cases significant error is introduced through the use of these correlations.
This paper evaluates the magnitude of such errors for oil and gas producers with regard to the estimation of flow capacity, completion efficiency, and effective drainage area. Synthetic cases are used as control sets in order to evaluate the sensitivity of the results to the various multiphase flow correlations and flowing conditions. In addition to synthetic (simulated) performance behavior, field cases are presented and the variance in estimated reservoir and completion properties is evaluated.
The technical contributions of this paper are:
Systematic evaluation of the effect of errors in flow rates and bottomhole flowing pressures on production data analysis — using both synthetic and field derived well performance data. Qualitative guidelines as the effect of errors in rate and pressure on estimated reservoir properties. Establishment of the most relevant pressure drop correlations for use in practice.
Quantifying Uncertainties Associated With Reservoir Simulation Studies Using Surrogate Reservoir Models
Authors: Mohaghegh S. D. 
Published: December 2007

Abstract
Reservoir simulation is routinely used as a reservoir management tool. The static model that is used as the basis for simulation is the result of an integrated effort that usually includes the latest geological, geophysical and petro-physical measurements and interpretations. As such, it is inherently a model with some uncertainty. Analysis of these uncertainties and quantification of their effects on oil production and water cut using a new and efficient technique is the subject of this paper.
Typical uncertainty analysis techniques require many realizations and runs of the reservoir model. In the day and age that reservoir models are getting larger and more complicated, making hundreds or sometimes thousands of simulation runs can put considerable strain on the resources of an asset team. This paper summarizes the results of uncertainty analysis on a giant oil field in the Middle East using a new technique that incorporates a Surrogate Reservoir Model (SRM).
A Surrogate Reservoir Model that runs and provides results in real-time is developed to mimic the capabilities of a full field model that includes about one million grid blocks and takes 10 hours to run on a cluster of twelve 3.2 GHz CPUs. This Surrogate Reservoir Model is used as the objective function of a Monte Carlo Simulation to study the impact of the uncertainties associated with several parameters on the model outcome, i.e. oil production and water cut is analyzed. The analysis can be performed individually on each of the 165 horizontal wells.
During the analyses of uncertainty, the Surrogate Reservoir Model will serve as an objective function for the Monte Carlo Simulation. In this study, uncertainties associated with several reservoir parameterts and their quantitative effect on cumulative oil production and stantaneous water cut are examined.
An Information Resource for Water-Management Solutions
Authors: Hite J. R. , Shaw D. C. , Warren J. M. 
Published: December 2007

Abstract
Halliburton has been directing a multi-year, cross-industry initiative to develop a web-based Information Resource for Water Management Technology. It aims to help the working engineer to understand current and up-to-date Water Management principles, technologies, best practices and lessons learned. We present the philosophy and methodology employed in the analysis, design and implementation of this important industry resource.
Stressed Shale Drilling Strategy—Water Activity Design Improves Drilling Performance
Authors: Rojas J. C. , Clark D. E. , Zhang J. 
Published: December 2007

Abstract
Non-aqueous drilling fluids are often chosen to drill troublesome shale formations in an effort to minimize wellbore instability problems. However, Gulf of Mexico (GoM) experience has indicated that when drilling in highly faulted areas, oil- and synthetic-based fluids do not always prevent wellbore destabilization. This is evidenced by wellbore collapse, and the resulting difficulty with holecleaning, tripping, logging and casing running.
It is known that the chemical, physical, and mechanical effects resulting from the interaction between the drilling fluid and the formation may degrade the stability of the borehole in the already weakened and stressed fault interval. Commonly, the practice has been to increase the drilling fluid salt content to enhance the borehole stability. The perception that low drilling fluid water activity is beneficial to wellbore stability is one that lends itself to a needed revision.
A detailed laboratory investigation using preserved shale core and drilling information have confirmed that the water activity of drilling fluids is often much lower than necessary. This study has shown that when drilling faulted or fractured shale, the correct, not higher salt content in drilling fluids will reduce wellbore collapse problems and improve drilling performance.
A laboratory method, which allows the quantitative measurement of water and ion movement during shale/mud interactions, combined with geological information, optimizes the salinity design of drilling fluid, which controls water and ion movement. Laboratory data and field cases from GoM drilling support the concept of optimum salinity to enhance borehole stability in naturally fractured formations as part of the stressed shale drilling strategy to improve drilling performance.
Interpretation of Heat Distribution, Remaining Oil Saturation, and Steamflood Potential of Block Wa38, Liaohe Field
Authors: Gao Y. , Yang S. , Zhou Y. , Jia L. , Sun H. , Zhang Y. , Castanier L. M. , Kovscek A. R. 
Published: December 2007

Abstract
The Shasan formation in Block Wa38, Liaohe oilfield is a typical, massive, permeable-sandstone, heavy-oil reservoir. Dead-oil viscosity at reservoir temperature is about 12615cp and the gross formation thickness is roughly 110 m. Cyclic steam injection using vertical wells has been applied successfully for about 10 years, but is reaching the economic limit. This work quantifies the distribution of heat throughout the block and locates the remaining oil saturation using analytical and numerical models. Methods for additional recovery as well as replacement technologies are explored using reservoir simulation. The first and most significant step of this work is the interpretation of the effect of multiple cycles of steam stimulation on the remaining oil saturation. Field data, semi-analytical methods, and numerical simulation are combined to obtain realizations of the distribution of heat and oil saturation throughout a block containing 18 wells. Results show that the remaining oil is mainly distributed in the lower portion of the reservoir layer and that the reservoir volume surrounding wells is desaturated. Thus, steam override influences the sweep efficiency. The reservoir is a candidate for continuous steam injection given the distribution of remaining oil and heat within the reservoir. Numerical reservoir simulation is used to optimize the parameters in the steam-flooding process using existing vertical wells and potential horizontal well candidates. High and low quality continuous steam injection is considered. Results show that further development using steam is effective at recovering oil with decreased operational cost. At the same time, the results also show that the heat communication between the wells from cyclic steaming operations aids greatly steam flood startup.
An Eulerian-Lagrangian Formulation for Compositional Flow in Porous Media
Authors: Wang H. , Ewing R. E. , Qin G. , Lyons S. L. 
Published: December 2007

Abstract
We derive an Eulerian-Lagrangian formulation for two-phase, multicomponent compositional flow in porous media with sources and sinks. The formulation can be used by many Eulerian-Lagrangian methods in solving the component mass balance equations. It can be combined with different types of pressure solvers in solving the coupled systems of compositional models. A full thermodynamic flash calculation is carried out to determine phase stability and composition.
Numerical experiments are presented to investigate the performance of the formulation and to compare it with the widely used upwind method for compositional flow. These results indicate that the Eulerian-Lagrangian formulation generates stable and accurate solutions that resolve moving steep fronts and are physically reasonable, even if it uses a time step two orders of magnitude larger than that used by the upwind method.