bluuebunny/crossref_metadata_2025_split huggingface dataset:
Process Optimization Review
Authors: Pontiff M. E. , Boyer B. E. 
Published: December 2007

Abstract
This paper is a description of a method called Process Optimization Review (PRO-OP). PRO-OP is a systematic approach used in production operations to identify opportunities to increase profitability while reducing green house gases (GHGs) such as methane. PRO-OP is a systematic approach to assess processes at new and existing facilities with an emphasis on energy efficiency, natural resource conservation and waste minimization. The PRO-OP process uses proven methane reduction methods in the USEPA's Gas STAR Best Management Practices (BMP) to optimize the facility. This methodology can be used in conjunction with a Process Hazards Analysis (PHA) for new facilities and prior to modification of an existing facility.
Sealed Connector System Eliminates Explosive Hazards and Saves Time in the Make-up Operation for Tubing-Conveyed Perforating Gun Systems
Authors: Fimreite H. , Nordaas L. , Novak A. , Watson Roger 
Published: December 2007

Proposal
When tubing-conveyed perforating (TCP)-guns have been needed, the traditional make-up method has been for the TCP and rig personnel to make them up manually using pipe wrenches on the rig floor. Efficiency in these efforts is critical to ensure a safe and reliable operation. When considering safety, this method is far from ideal since in an ideal situation, no personnel would be required to handle the explosive equipment on the rig floor while it is being assembled into the well.
A new system that considerably improves safety will be discussed in this paper. This new system, which encloses each end of the gun assembly, allows handling by the rig equipment and eliminates the need for human intervention. With these connectors, TCP-Gun assembly handling has improved safety, efficiency, and is compliant with the appropriate regulations.
Injection Testing To Determine Reservoir Properties
Authors: Goodman C. , Howell R. , Gabbard J. 
Published: December 2007

Abstract
In many locations, totally evaluating the quality of a reservoir based on conventional logs alone is difficult. This difficulty is especially present in lower-permeability reservoirs. Often, conventional logs can allow the operator to pass up zones that may be more productive than indicated on a conventional porosity cutoff. In such cases, a zone is perforated and allowed to flow to get a better evaluation of the zone and its production potential. However, if the zone does not flow to expectations, the operator may face a real dilemma: is it a poor-quality reservoir, or is some sort of damage prohibiting flow? This question can be very daunting and may not be easily answered, especially if the well will not flow adequately for a buildup analysis within a reasonable time frame.
In this paper, the potential for using a small injection test and the subsequent pressure fall-off to analyze the reservoir pressure and permeability is evaluated. Many benefits could be derived from using an injection test for reservoir analysis. Some are obvious, such as the capability to determine permeability and reservoir pressure, but this test can also be advantageous because these properties can be determined without flowing the well (which in some circumstances may be difficult and/or costly).
In this paper, a deep Atoka Wash well in Western Oklahoma is evaluated. The results of the fracture injection test are discussed, as well as how these results compare with a conventional buildup analysis.
Well Testing Best Practice
Authors: Zheng S.-Y. , Corbett P. 
Published: December 2007

Abstract
This paper will present study results from a ten-year long oil industry sponsored research project in this subject area. The survey of well testing practice covered situations from a range of major oil companies in China, Europe and Russia, which reflected problems that have long existed. These issues were further confirmed at the 2002 SPE well testing Forum. It was realised there is a need to promote best practice in the oil industry, and in well testing in particular, and that was the motivation for this paper.
Well testing, regarded as transient pressure testing, is usually very expensive. Bad testing data resulting from lack of design, preparation and unsupervised operation are really expensive. The contribution from the test to your asset is negative if a decision is made based on the information derived from non- representative data. Therefore, why not carefully prepare or design your test beforehand? There should be no excuse after spending two million dollars for a test and failing to deliver the information you expected. In our eleven years of research and teaching experience worldwide in the subject area, we found that well test interpretation engineers need skills other than in the subject itself in order to get more value from well testing. There is also a need to clarify the ambiguity in some well testing concepts such as data, information, analysis and interpretation, in order to develop a test procedure that is generally easy to follow and understand. In this paper, the study results will address all issues from justifying a test to the right procedures to conduct and interpret a test. The definition of a transient pressure test and a PI test, well test objectives and alternative measurements available to consider in the oil industry, as well as the advantages and disadvantages of these measures, are critically reviewed. We term this approach: Well Testing Best Practice (WTBP).
Ensuring Effective Stimulation Treatments in Difficult Completions
Authors: Willemse M. , Mostafa O. , El-Ashry M. , Abdallah I. , Sattar A. A. , Waheed A. , Conrad B. 
Published: December 2007

AbstractAchieving effective stimulation across zones not readily accessible is a common challenge in the oilfield. Several authors1-3 have presented case histories in which horizontal wells completed with slotted liner, gravel pack, internal gravel pack, or plain sand screens were difficult to stimulate because there was no easy way to effectively remove drilling fluid filter cake from the wellbore walls. Similar inaccessibility is encountered when dealing with straddled completions, where out of necessity, the producing zone is placed behind straddle packers that are extremely challenging to reach. Another accessibility problem is encountered when a "fish" becomes caught up across the perforated interval and accessibility is again denied.Should such wells produce trouble-free and meet expectations, there is not much to ponder; but if not, the options for executing an enhanced stimulation treatment have been limited. Generally, treatment has consisted of pumping and squeezing away the treatment into the perforations and hoping for the best. The preferred technique is to improve the injectivity into the perforations by "spotting" reactive fluids at the perforations or using some type of mechanical action such as "perforation jetting" to break up blockages in the perforation tunnels. This is only possible when perforations or pays are accessible through the wellbore.These problems become more complicated if the zones of interest are sandstone reservoirs. A study4 in the late 1990s revealed a success ratio in the 30–40% range when treating such formations.This paper primarily deals with a case history in which a sandstone reservoir, not previously matrix-acidized, was producing at sub-par rates, eventually declining to a negligible production status. The zones were completed between straddle packers and were only accessible through a sliding side door (SSD), 100 ft above the perforations.The prudent decision was to stimulate, but make all efforts to maximize the chances of success. Apart from applying the best practices in sandstone acidizing technology, a true fluidic oscillator (TFO) was included as a stimulation tool. This tool provides a continuous pressure pulse in the fluid system that allows solids buildup within the perforations to fatigue and break up while the acid system works on the rock matrix.The results from the treatment of this well were exceptional and will be detailed in this paper. The production improvement was 10-fold over its prestimulation performance.
A Decision Analysis Approach to Hydraulic Fracture Optimization in the W31S Stevens Oil Zone, Elk Hills Field, California
Authors: Agiddi D. O. 
Published: December 2007

Abstract
Since 1999, hydraulic fracture stimulation in the layered W31S Stevens reservoir, Elk Hills, has increased productivity of new infill wells. One to six months increase in production of well over 300 percent in barrels of oil equivalent per day (BOEPD) has been achieved. Since 2002, optimization in treatment fluid has lead to a change from conventional borate cross-linked, guar-based polymers to new gel technologies with low polymer concentrations designed to minimize formation damage - an important consideration for the declining reservoir pressure and the low permeability rock in W31S sand. New available fluids combine stable downhole rheology with enhanced visco-elastic properties to provide good proppant transport capabilities.
Infill drilling activity in the W31S zone has recently moved from the flank areas of the 31S structure to up-dip locations with higher vertical rock stress difference, less thick pay, and higher gas-to-oil ratios. Different fracture monitoring and diagnostic data, including a down hole treatment pressure survey, has been acquired to characterize fracture growth profile and to optimize the W31S fracture design model. Review of recent well performance and treatment data suggests that, though productivity gains are realized from improved clean-up characteristics of the new fracturing fluids, achieving full vertical coverage and design conductivity remains a great challenge. This has huge implications for the economics of the development drilling in the up-structure locations.
This paper introduces a quantitative fracturing treatment option model as a useful communications tool for selecting the treatment with the best chance for economic success.
Achieving Low Emissions in an Internal Combustion Engine Using Off-Spec Produced Fuel Gas
Authors: Cassinis R. , Larson W. 
Published: December 2007

Abstract
Tidelands Oil Production Company was producing associated gas containing high levels of CO2 that did not meet the specification of the local utility and was being flared. An alternative use for the gas was to fuel a 2,000 horsepower internal combustion engine to drive a high-pressure water injection pump. However, the strict emission level requirements for NOX, CO and VOCs at the Southern California location required that a new emissions control design be configured and used. This paper will discuss the system design, economics and the steps taken to enable the internal combustion engine to meet the strict emissions standards of the region while using off-spec, high CO2, produced gas.
Analysis of Completion and Stimulation Techniques in a South Texas Field Utilizing Comprehensive Reservoir Evaluation
Authors: Larkin S. D. , Pickrel H. M. , Lattibeaudiere M. G. , Marti S. K. , Atwood K. , Poe B. D. 
Published: December 2007

AbstractThis paper will evaluate the efficiencies of completion methods in a South Texas field utilizing the latest techniques in post fracture production analysis. Stimulation effectiveness for each frac stage in ten multi-zone wells is evaluated.Effective values for reservoir and fracture parameters including porosity, permeability, propped fracture half-length, fracture conductivity and fracture face skin will be derived using production analysis techniques and will be compared for the different completion methods employed. The holistic model will incorporate the geological, petro-physical properties of the formation and production logging data.Actual stimulation and production data from ten wells in the same area are used in this analysis. Five of the wells were completed in single-stage fracture stimulation across multiple perforated intervals. Five wells were completed with two-stage fracture stimulations across multiple perforated intervals. The multiple layer fracturing technique was utilized in all wells. The study will derive the effective reservoir and fracture parameters using production allocation for each interval in the multiple interval wells.This paper will compare the different completion techniques using this methodology and will discuss a predictive model for future stimulation work in this area. This methodology will also help in identifying under-stimulated zones in existing wells that may be candidates for re-fracturing.
Water Control Problems and Solutions-Los Angeles Basin Statistics and Case Histories
Authors: Swanson G. , Ershaghi I. 
Published: December 2007

Abstract
This paper presents a statistical overview of water control issues currently important to Los Angeles Basin operators of high water cut, mature, turbidite waterfloods. Certain observations, analyses and conclusions may be of interest to others working with high water cut fields. Case studies demonstrate reasonable costs and economic payouts for water control efforts.
Several LA Basin operators contributed water control-related information to a consortium study sponsored by the the U S DOE PUMP program and the California Energy Commission and managed by the Petroleum Technology Transfer Council. Data from seven fields, which together account for more than half of LA Basin's production, were analyzed in order to identify key factors which contribute to water control problems and solutions.
Information for wells with poor or good performance were obtained from the operators and analyzed. Parameters which differed significantly among categories of injectors and producers were characterized. In total, 60 injectors and 67 producers were analyzed in detail, yielding several statistics and observations of interest.
Water control strategies were also analyzed as part of this study. Seventeen water control jobs, costing $25,300 on average, resulted in an average payout of 7.1 months. Operators’ policies regarding computation of water production, treatment and re-injection costs were reviewed in detail, resulting in a weighted average cost of $.23/bbl of water produced. Operators investing more than $.02/bbl in water control were observed to hold water cut increases to less than 0.2%/year, while those spending less than $.01/bbl experienced annual water cut increases in excess of 0.4%/year.
All statistics highlighted above were extracted from several databases that allowed many more analyses to be conducted, including individual operator and/or field comparisons to basin-wide averages.
Automatic History Matching of Naturally Fractured Reservoirs and a Case Study
Authors: Cui H. , Kelkar M. 
Published: December 2007

Abstract
In naturally fractured reservoirs, the fracture intensity (density) control the fracture permeability and the dimensions of matrix blocks, and hence govern the reservoir production performance and oil recovery process. In the last decade, great progress has been made in the characterization of natural fracture system of naturally fracture reservoirs. The statistical fracture intensity model can be constructed by integrating the direct local data, such as core and image log data, and field scale data derived from seismic attributes, fault-related-strain-field, structural information (curvature), etc. The static fracture model must be converted into flow simulation model for dynamic simulation, and must be adjusted to honor the production history to perform production performance prediction and optimal development planning.
This paper discusses the development of a novel method of conditioning the fracture intensity model to the production data. This is achieved by making the sensitivity coefficients available of production data with respect to fracture intensity through the building of correlations between fracture intensity and fracture permeability and fracture/matrix coupling factor.
Gradient simulator and adjoint methods are used to calculate the sensitivity coefficients of production data to the parameters of fracture and matrix blocks. Both two methods usually involve solving of a great number of matrix equations. Sparse LU decomposition is used to solve the matrix equations to improve the computational efficiency of sensitivity coefficient. To the best of our knowledge, the particular implementation of the sparse LU direct methods in automatic history matching is new to the petroleum engineering literature.
The proposed method and developed software is validated by applying to a giant Middle East carbonate naturally fracture reservoir.
Innovative Approach to Multiple Gas Fields Simulation through the Application of the Mixed Black Oil and Compositional Formulation
Authors: Bargiggia C. C. , Giordano D. , Monico C. 
Published: December 2007

Abstract
A mixed formulation technique, coupling compositional and black oil mode, was used in a regional simulation model to study the associated liquid hydrocarbon production of two wet gas fields still in the development phase in communication through the aquifer with other gas fields already on production.
Initially, a regional 3D black oil model was built. The history match was carried out with the main target to reproduce the measured pressures in all the fields.
Since it was necessary to predict the associated liquid hydrocarbon production of the new fields, their relevant model zone was converted to compositional formulation in the forecast simulation runs.
With the mixed model approach, different formulations coexisted in the same model with the possibility to be switched on or off during the simulation run. The advantage was to perform a local compositional control in the production forecast, maintaining black oil simulation in the remaining part of the model. The method was validated by comparing the mixed formulation production profiles to the ones obtained with the black oil simulation.
This technique enabled us to predict the rate and the characteristics of the hydrocarbon stream in the two gas fields. A further benefit was a remarkable saving of the CPU time, due to the use of black oil simulation outside the two new gas fields.
Integrated Field Development for Effective Scale Control throughout the Water Cycle in Deep Water Subsea Fields
Authors: Jordan M. M. , Mackay E. J. 
Published: December 2007

AbstractScale control in produced fluids as water follows the cycle of injection, production, processing and reinjection in oil production facilities is, in many cases, critical to the effective production of hydrocarbons in a safe, economic and environmentally acceptable manner.This paper focuses on the challenges to scale control in deepwater reservoirs, and describes the scale control measures that are designed into the field development plan based on the integration of reservoir simulation, completion design technology and production chemistry. Emphasis is placed on the need to consider the full life cycle of the field, considering a range of development scenarios, such as water flooding with seawater, desulphated seawater, produced water re-injection, aquifer water injection and primary depletion.Advanced fluid flow and reaction calculations that account for in situ scaling reactions and the impact on the produced brine chemistry are used to provide data to refine the economic models used to identify the optimum scale management technologies. The various functions that must be carried out for effective scale management at the CAPEX and OPEX phase are outlined.The paper clearly demonstrates how, by using an integrated team that includes personnel drawn from operating company, chemical service company and research institute backgrounds, a multi-disciplinary approach may be used to integrate engineering and chemical solutions to effectively arrive at the most economic scale control programme for these challenging fields.
Screening of Reservoir Types for Optimisation of Intelligent Well Design
Authors: Ebadi F. , Davies D. R. , Reynolds M. , Corbett P. W. M. 
Published: December 2007

AbstractIntelligent completions focus on delivery and management of production flexibility. Intelligent Well systems Technology (IWsT) deliver the ability to monitor and control production without the need for conventional interventions. Installation of intelligence at the well level is not always a guarantee for success - it must be shown to add value to gain acceptance. This paper uses a new workflow to investigate the premise that some reservoir types are inherently more suited to IWsT application than others.A series of generic reservoir scenarios, based on property distributions derived from real field data and operational oilfield models, were built. These geological scenarios were tested to determine the added value from IWsT compared to standard completions. Situations in which IWsT proved particularly successful, and situations which showed little or no value, have been identified.Results show that IWsT can control uneven, invading fluid-fronts that have developed along the wellbore length due to permeability differences, reservoir compartmentalisation or different strength aquifer/gas cap support. Downhole Interval Control Valves (ICVs) are capable of managing wellbore friction effects and such differences in zone pressure along the wellbore. Oil recovery factors improve and water production rates reduce with the correct choice of the number of ICVs installed and their location along the length of the wellbore. However, the degree of improvement is dependent on the reservoir type (Layered, Faulted, Channelised, etc.) and the distribution of porosity and permeability within it. This study provides a new look at the applicability of IWsT in a wide range of reservoir types.In the next stage, a range of realizations of a reservoir model were generated, so that the degree of heterogeneity was increased systematically in the models by changing the Coefficient of Variation and the Correlation Length. The added value from an intelligent well installed in these reservoir realisations was evaluated.The results were analysed in terms of correlation length vs. coefficient of variation. A potential IWsT applicability envelope was developed. These plots can be used as an initial screening tool for deciding when, and when not, to implement IWsT.The final decision on whether to install such equipment will be made by an engineer making a detailed technical and economic analysis for the particular case being studied. This last phase is outside the scope of this paper.