bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fracture-Matrix Transport Dominated by Capillary-Driven Flow in Layered Sandstone
Authors: Karpyn Z. T. , Halleck P. M. , Grader A. S. 
Published: December 2007

Abstract
Fluid transport in reservoir formations under quasi-static conditions is strongly dominated by capillary forces. These forces are a macroscopic manifestation of complex molecular interactions between fluids and solids inside the intricate pore structure of rocks. In naturally fractured reservoirs, spontaneous capillary imbibition is an important recovery mechanism since waterflooding of the disjointed matrix cannot be accomplished by forced displacement.
The goal of the present experimental work is to establish a detailed reference case for the validation of numerical models of capillary-driven flow in fractured formations. This paper presents experimental results of two-phase capillary-driven flow in a layered Berea sandstone sample with a single longitudinal fracture. The sample was artificially fractured using a modified Brazilian test that resulted in an extensional longitudinal fracture oriented perpendicularly to the natural bedding planes of the rock. Non-destructive high-resolution X-ray CT imaging allowed identification of localized cocurrent and countercurrent flow during spontaneous capillary imbibition.
Three distinctive flow intervals were identified during spontaneous imbibition. Those are early, intermediate, and late time. The presence of bedding planes in the rock's structure determines the shape of the imbibing front during early-time imbibition. The imbibing front advances faster through low porosity/permeability layers due to higher capillary forces. Cross-layer fluid exchange tends to level the imbibing front during the intermediate imbibition stage. Countercurrent flow controls fluid transport during the early and intermediate intervals, while both cocurrent and countercurrent flow mechanisms coexist at late time. Results from this experimental work present strong evidence of localized hysteretic behavior. Drainage, imbibition, and transition zones characteristic of countercurrent flow are clearly identified as a function of time.
After-Closure Analysis for Naturally Fractured Reservoirs: Field Examples
Authors: Chipperfield S. 
Published: December 2007

Abstract
Economic optimization of fracture stimulation designs requires accurate reservoir description (ie. permeability and permeability thickness) and an understanding of the deliverability mechanism (ie. natural fractures versus conventional matrix). This paper presents a technique which allows an engineer to evaluate a mini-frac injection in a similar manner to a conventional pressure transient test for the identification of productive natural fractures. Following a brief theoretical background to this new methodology, this paper provides a field validation study in oil and gas fields on two continents.
Identifying natural fractures drives certain changes in stimulation design. Techniques designed specifically to stimulate natural fractures include low gel loadings, energized fluids and 100 mesh sand for natural fracture preservation1,2.
A recently published mini-frac evaluation technique using the After-Closure pressure information3 provides a methodology which can identify productive natural fractures. Using this methodology, this paper delivers a retrospective evaluation of mini-frac information using data from tight gas fields in Central Australia and an oil field in Algeria. In addition, the results are validated with independent constraints such as pre-closure mini-frac analysis, conventional well testing, image logs and core analysis.
Finally, the results of this evaluation are distilled into a simple field implementation methodology which can be incorporated into a conventional pre-frac injection sequence.
Condensate Skin Evaluation of Gas/Condensate Wells by Pressure-Transient Analysis
Authors: Shandrygin A. , Rudenko D. 
Published: December 2007

Abstract
Condensate blockage of gas-condensate wells is widely recognized as an important problem. In dry-gas wells, zone damage (blockage) is typically quantified by skin factor, which is obtained by interpreting pressure-transient testing results. In gas-condensate wells, however, the complex behavior of gas-condensate fluid creates problems for application of commonly used interpretation methods for estimating condensate skin. This paper proposes a procedure for evaluating skin in gas-condensate wells, using a simplified numerical model. The proposed procedure is based on a single-phase approach, treating condensate as immobile, without phase transitions between gas and condensate. This reduces the number of input parameters and dramatically decreases computational cost. Radial condensate distribution is described using condensate-bank radius and maximum condensate saturation as regression parameters for fitting modeled build-up pressure curves with well-test data. Evaluated bank parameters provide an estimate of the skin caused by condensate blockage in the near-wellbore zone.
The procedure was validated for a radial reservoir. Synthetic well-test data generated using compositional simulator was used to conduct a sensitivity study for various production regimes and reservoir properties.
The proposed procedure provides a reasonable estimate for the condensate skin value. However, it has some limits of applicability like any other method not using compositional modeling to simulate gas-condensate flow in porous media.
Rock Typing as an Effective Tool for Permeability and Water-Saturation Modeling: A Case Study in a Clastic Reservoir in the Oriente Basin
Authors: Guo G. , Diaz M. A. , Paz F. , Smalley J. , Waninger E. A. 
Published: December 2007

Abstract
In clastic reservoirs in the Oriente basin, South America, rock-quality-index (RQI) and flow-zone-indicator (FZI) prove to be an effective technique for rock type classifications. It has long been recognized that excellent permeability-porosity relationships can be obtained once the conventional core data are grouped according to their rock types. Furthermore, it was observed from this study that the capillary pressure curves as well as relative permeability curves also show close relationships with the defined rock types in the basin. These results lead us to believe that if rock type is properly defined, a realistic permeability model, a unique set of relative permeability curves as well as a consistent J function can be developed for a given rock type. The procedure for implementing this technique in our reservoir modeling is described in the paragraphs below.
Conventional core data were first used to define the rock types for the cored intervals. The wireline log measurements at the cored depths were extracted, normalized, and subsequently analyzed together with the calculated rock types. A mathematical model was then built to predict the rock type in uncored intervals and in uncored wells. This allows the generation of a synthetic rock type log for all wells with modern log suites. Geostatistical techniques can then be used to populate the rock type throughout a reservoir.
After rock type and porosity are properly populated, the permeability can be estimated using the unique permeability-porosity relationship for a given rock type. The initial water saturation for a reservoir can subsequently be estimated using the corresponding rock type, porosity, and permeability models as well as the rock-type-based J functions. It was observed in our study that a global permeability multiplier became unnecessary in our reservoir simulation models when the permeability model is constructed using this technique. Consistent initial water saturation models (i.e., calculated and log measured water saturations are in excellent agreement) can be obtained when the proper J function is used for a given rock type. As a result, the uncertainty associated with volumetric calculations is greatly reduced as a more accurate initial water saturation model is used. The true dynamic characterisitcs (i.e., the flow capacity) of the reservoir are captured in the reservoir simulation model as a more reliable permeability model is used.
Evolution of Real-Time Operations Monitoring: From Concept to Global Implementation
Authors: van Oort E. , Rosso R. , Cabello-Montero J. 
Published: December 2007

Abstract
The unique challenges posed by deepwater wells of ever-increasing complexity continue to force operators and service companies to explore new and innovative well delivery solutions. In early 2002, Shell Exploration and Production Americas took an important step towards well performance optimization with the initiation of a pilot study into real-time, remote monitoring of exploration and production wells in the Gulf of Mexico (GoM). Starting with a small-scale "war room" concept with limited scope, the pilot quickly grew into the current New Orleans-based "Real-Time Operations Center" (RTOC), which monitors all offshore wells in the GoM as well as major exploration wells globally. Main objectives of this multidisciplinary collaboration center are to enable more pro-active well planning and improve well execution by reducing non-productive time (NPT) and invisible lost time (ILT). The success of the RTOC, as well as that of other independent well visualization and monitoring pilots in the Shell Group, has meanwhile led to significant steps towards global expansion and coverage.
In a follow-up to earlier papers1,2, we describe the current state-of-the-art in real-time operations monitoring technology deployment in the RTOC, and how it has evolved from the original pilot phase. We discuss the center's various activities, demonstrate how they add value and how this value is being measured. Key hurdles and success factors for implementation of an operations center are summarized. Moreover, the preliminary learnings from global deployment are shared.
The information may serve as a blueprint for the planning, design and operation of a real-time operations center both locally, regionally and globally. The expansion of real time engineering and monitoring services across the globe is a challenging and pioneering undertaking. Consequently, we hope that this paper will help to lead the way in expanding this capability in the oil and gas industry in general.
Use of DST for Effective Dynamic Appraisal: Case Studies From Deep Offshore West Africa and Associated Methodology
Authors: de la Combe J. L. B. , Akinwunmi O. , Dumay C. , Tachon M. 
Published: December 2007

Abstract
In the emerging West Africa deep offshore region, where exploration is booming, the turbiditic series reservoirs are mostly structurally trapped with a stratigraphic component. Faulting is severe inducing high compartmentalisation. Evaluation of connectivity and characterisation of the reservoir heterogeneities before development decisions are the main challenges.
These two long DST acquired at a relatively early stage of the appraisal were a game changer for the development project. Both demonstrated large scale reservoir continuity in a complex geological setting, which in turn provided extraconfidence on the feasibility of a large scale development project. The confrontation of this wide scale dynamic information to seismic data and geological concepts allowed significant optimisation of the remaining appraisal sequence.
Testing methodology, based on Total experience, advocates the setting of two cycles of draw-down and build-up to generate significant depletion between the two build-up's. This test sequence allows discriminating between geological models matching the derivative and assesses a minimum hydrocarbon connected volume.
The first case study concerns a third appraisal well drilled to recognise the turbiditic series of Late Miocene age in the Southern panel of a structure discovered recently. This test allowed us to prove a minimum oil connected volume of at least 120 MMbbls, much larger than the pre-test volume of 55 MMbbls estimated from seismic interpretation, and proved an extension of good reservoir facies beyond the seismic visibility limit.
In the second case study concerning an exploration well aiming to recognize the turbiditic sands of the same age, the shallower oil-bearing interval was tested. The fault density around the well being quite high, it was important to know if the faults would act as dynamic barriers. This test proved a minimum connected volume of around 90 MMbbls, and indicated that the encountered reservoir facies was developable as the high fault density around the location of the well did not negatively affect the dynamic performance. In this well, only one out of several faults at 130 meters from the well, within the investigated area of the test, acted as a dynamic barrier.
Production Management Information Challenges in the Digital Oilfield
Authors: DeVries S. 
Published: December 2007

Abstract
The Digital Oilfield needs to distribute information to personnel in many locations, companies and situations while satisfying requirements for privacy, protection of intellectual property, and suitability for new business processes. All of this must be accomplished with an appropriate set of standards. A key example is an escalating condition, such as a flow assurance problem, that requires the operating company to share information with one of several competing service companies. How does the access easily change based on the situation and supervisor decisions? How does a busy, remote, mobile expert know when to look at this information? How is this activity tracked? How does each organization protect their intellectual property? This transcends the domain of information technology and petroleum engineering expertise. This paper examines the three main challenges and proposes two new approaches to address them.
Unconventional RPM Applications in Hydraulic Fracturing
Authors: Leal J. , Gonzalez M. A. , Villa G. , Garay R. , Castro A. 
Published: December 2007

AbstractIn fracturing applications, addition of the Relative Permeability Modifiers (RPM's) to water base fracturing fluids, preferably to pre-pad and pad stages, can provide multiple potential treatment enhancement benefits. The RPM may reduce post-stimulation water production, and increase fracturing fluid efficiency. RPM's may also pump as a postfracturing treatment at matrix rates following load recovery. After the RPM treatment in an oil well, hydrocarbon solvents compatible with the hydrocarbon-bearing interval compose the recommended flush solutions. These solvents may include aromatic solvents such as xylene, diesel or mixtures of diesel and aromatic solvent. This flush is designed to reconnect the hydrocarbon reserves to the wellbore in an effort to accelerate return of oil production. In this application, the diesel base frac fluid accomplished this function.In water sensitive hydrocarbon bearing is desirable to avoid excessive use of water base fluids. Good results are obtained using oil base fracturing fluids. However, RPM's cannot be added directly to oil base fluids. To address this issue, an unconventional method was proposed and executed with successful results. Prior to the propped frac treatment, a water base frac fluid with RPM polymer is pumped at fracturing rates, with a volume calculated to occupy the formation with an equivalent fracture geometry slightly larger than the expected created geometry of the subsequent propped oil/solvent based frac fluid treatment.This paper describes guidelines for candidate selection for this application, analysis and logs to optimize treatments, advantages obtained with this method, and case histories in a Colombian field. The RPM used is a synthetic ter-polymer based on acrylamide chemistry.
Integration of Artificial Intelligence and Lean Sigma for Large-Field Production Optimization: Application to Kern River Field
Authors: Popa A. , Ramos R. , Cover A. , Popa C. 
Published: December 2007

AbstractThis paper represents an integration of artificial intelligence and lean sigma techniques to achieve large field production optimization. The first part of the methodology (detailed in SPE 90266 "Zonal Allocation and Increased Production Opportunities Using Data Mining in Kern River"1) involves data management and predictive data mining for increased production opportunity identification. It utilizes a set of data mining tools including clustering techniques and neural networks to identify new candidates for clean-outs, perforating, sidetracks, deepening, and other types of workovers. Furthermore, the expert system was used to predict the estimated production increase for these candidates. The second part of the methodology optimizes the implementation and post-workover follow up of the opportunities identified in part one. It involves the use of lean sigma tools such as value stream mapping, level loading, continuous flow production, standard operating procedures, and kanbans which optimize execution cycle time, peak oil production, decision making process, cost, and safety2. This approach was successfully applied and executed in the Kern River field.
Tougher Concrete Structures To Service and Protect Oil and Gas Operations
Authors: Moncarz P. D. , Krstulovic-Opara N. 
Published: December 2007

Abstract
Large on-shore and off-shore facilities for production, loading and unloading, and storage of petroleum products are being constructed with the use of reinforced concrete. Recent examples include the monumental platforms associated with the Sakhalin II development, and the development of new LNG facilities driven by the world demand for transportation of large quantities of natural gas over large distances. The political climate of the 21st century dictates a much higher attention level to questions of safety and security of these facilities. Terrorist threat requires not only a heightened surveillance and threat-response readiness, but also the incorporation of design features making such threats less likely to succeed. These design features include both structural and material level considerations. The authors discuss some of the currently available approaches to making concrete structures tougher to terrorist attacks while also making them more serviceable and longer lasting. Experience from research and field studies on fiber reinforced concrete, on slurry infiltrated mat concrete, and on Kevlar wrapping of critical concrete structure elements in high seismicity areas are some of the discussed topics. Suggestions are made how these examples could lead to toughening of oil and gas concrete facilities or of concrete protective barriers.
Risk and Uncertainty Management—Best Practices and Misapplications for Cost and Schedule Estimates
Authors: Peterson S. K. , De Wardt J. , Murtha J. A. 
Published: December 2007

Abstract
Risk management, risk analysis, and uncertainty analysis are still-growing trends in cost and schedule estimating. Engineers and managers alike have been lead to believe that correct application of best practices will ensure that operations achieve their objectives on time and within budget.
Unfortunately, a number of misapplications, misunderstandings, and mistakes have threatened to endanger the continued useful growth of this trend. Insufficient tools and / or incorrect use of the available tools have allowed creation of a false sense of security which is shattered by loss of objectives and time / cost overruns. It is very important that the industry understands and chooses the correct applications, and has realistic expectations.
This paper will present best practices for applying risk management, risk analysis and uncertainty analysis to capital expenditure cost and schedule estimates. In addition to outlining our recommended process, we will highlight current misapplications that, in our opinion, are potential barriers to the continued growth of this valuable management tool.
Effect of Operating Valve Performance on Stability of Gas Lift Wells
Authors: Fairuzov Y. V. , Guerrero-Sarabia I. 
Published: December 2007

Abstract
Heading (flow instability) is a common problem in the operation of continuous flow gas-lift wells. One of the key elements, which affect the gas-lift stability, is the operating valve. Several operating gas-lift valve designs are currently used in practice. A new valve design, based on the use of a supersonic nozzle ("the nozzle-Venturi gas-lift valve"), was recently proposed in the literature. In most cases, it is very difficult to estimate apriori (at the design stage) how the type of the gas-lift valve and its design parameters affect the stability of a gas-lift system to be operated at a given operating condition. In this paper, the effect of operating valve design on gas-lift stability was studied. It is shown that the gas-lift stability maps proposed in an earlier study may facilitate the selection of the operating valve design. Different valve designs were considered: the conventional orifice and gas-lift valves, as well as the nozzle-Venturi valve. Gas-lift stability maps were constructed for each operating valve design. Advantages and disadvantages of the considered valve types are discussed from the point of view of the gas-lift stability. Based on the comparison of the gas-lift stability maps, recommendations on the selection of the operation valve type were elaborated.
North Slope Heavy-Oil Sand-Control Strategy: Detailed Case Study of Sand Production Predictions and Field Measurements for Alaskan Heavy-Oil Multilateral Field Developments
Authors: Burton R. C. , Chin L. Y. , Davis E. R. , Enderlin M. , Fuh G. , Hodge R. , Ramos G. G. , VanDeVerg P. , Werner M. , Mathews W. L. , Petersen S. 
Published: December 2007

Abstract
The North Slope of Alaska has billions of barrels of heavy oil residing in largely undeveloped reservoirs. Despite this large volume of heavy oil in place, the majority of reserves development on the slope to date has been focused on light crude. However over the past 20 years Arco, BP, Conoco and now ConocoPhillips have begun to develop the North Slope’s vast heavy oil resource base. Recently a sand/solids control study was undertaken by ConocoPhillips and BP in order to determine the most economic strategy for solids control and well design in future heavy oil developments.
The study was integrated across companies, organizations and discipline boundaries in order to include completion, rock mechanics, laboratory research, drilling, reservoir, geological, operations, facilities and field personnel. With this diverse team, actual solids production and solids predictions were investigated from a number of different perspectives. Solids production predictions were made based on core measurements, log analysis, simulators that predict formation failure and sand production rate, laboratory core flow tests, 2 years of field shakeout data, and multiple field measurements of solids production. Probabilistic predictions were then generated based on these investigations rather than deterministic "best guesses" for the economic analysis. These different methods for predicting solids production will be discussed and illustrated in this case study.
The study and ensuing strategy determined that sand management or using non-sand exclusion slotted liners and sand tolerant facilities was the highest value development scenario over the life cycle of the North Slope Heavy Oil Developments.