bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analysis of Hydrocarbon Production in a Critically-Stressed Reservoir
Authors: Miskimins Jennifer L. , Knight Constance Dodge 
Published: December 2007

Abstract
The North La Barge Shallow Unit (NLBSU) produces from the Mesaverde formation at depths of 2000 ft (610 m). The NLBSU exhibits four types of production behavior including fracture-dominated, matrix-dominated, fracture/matrix combination, and significantly reduced production near faults. The fracture-dominated production behavior is centralized in a structurally complex, highly stress-controlled region, which includes a horsetail splay termination of a strike-slip fault. This faulted region results in critically stressed natural fracture production.
Faults play a dual role in controlling production histories at the NLBSU. In addition to critically stress natural fracture production, several producing wells that were drilled in fault damage zones exhibit significantly reduced production performance. The presence of fault damage zones takes precedence over the occurance of natural fractures in terms of reservoir enhancement and results in poor production performance.
Knowledge of these types of production controls can aid in reservoir management throughout the life of a field.
Quantification of Uncertainty in Recovery Efficiency Predictions: Lessons Learned from 250 Mature Carbonate Fields
Authors: Sun S. Qing , Sloan Rod 
Published: December 2007

Abstract
The most prominent aspects of carbonate reservoirs are their heterogeneity, variable wettability and dual pore network, which collectively contribute to complex fluid flow and uncertainty in reservoir performance and recovery efficiency predictions. A review of ultimate recovery efficiency in 250 mature carbonate fields from around the world provides constraints for quantifying uncertainty in recovery efficiency predictions. Key determinants of ultimate recovery are fluid type, pore network, reservoir heterogeneity, drive mechanism and wettability. Development strategies and reservoir management techniques play crucial roles in maximizing expected ultimate recoveries for given reservoir/fluid parameters. Five main fluid type/carbonate reservoir classes, with characteristic ultimate recovery distributions and controls are: (1) heavy and viscous oil reservoirs, in which recovery factor (RF) is controlled by fluid viscosity variations, field size and application of horizontal drilling, (2) karstic/fractured carbonate oil reservoirs, in which RF is controlled by fracture intensity, matrix permeability, wettability and drive mechanism, (3) conventional carbonate oil reservoirs, in which RF is controlled by reservoir connectivity, permeability and mobility ratio, (4) organic buildup oil reservoirs, in which RF is controlled by nature and size of organic buildups and diagenetic modifications, and (5) gas/condensate reservoirs, in which RF is controlled by aquifer encroachment and condensate drop-out. Examination of actual case histories reduces uncertainty in predevelopment recovery efficiency predictions and shows what is possible in new or old fields.
Automatic History Matching in a Bayesian Framework, Example Applications
Authors: Zhang Fengjun , Skjervheim Jan Arild , Reynolds A. C. , Oliver D. S. 
Published: December 2007

Abstract
The Bayesian framework allows one to integrate production data and static data into a posteriori probability density function for reservoir variables (model parameters). The problem of generating realizations of the reservoir variables for the assessment of uncertainty in reservoir description or predicted reservoir performance then becomes a problem of sampling this posteriori pdf to obtain a suite of realizations. Generation of a realization by the randomized maximum likelihood method requires the minimization of an objective function that includes production data misfit terms and a model misfit term that arises from static data. Minimization of this objective function with an optimization algorithm is equivalent to the automatic history matching of production data with a prior model constructed from static data providing regularization. Because of the computational cost of computing sensitivity coefficients and the need to solve matrix problems involving the covariance matrix for the prior model, this approach has not been applied to problems where the number of data and number of reservoir model parameters are both large and the forward problem is solved by a conventional finite difference simulator.
In this work, we illustrate that computational efficiency problems can be overcome by using a scaled limited memory Broyden-Fletcher-Goldfarb-Shanno (LBFGS) algorithm to minimize the objective function, and using approximate computational stencils to approximate the multiplication of a vector by the prior covariance matrix or its inverse. Implementation of the limited memory BFGS method requires only the gradient of the objective function which can be obtained from a single solution of the adjoint problem; individual sensitivity coefficients are not needed. We apply the overall process to two examples. The first is a true field example in which a realization of log-permeabilities at 26,019 grid blocks is generated by the automatic history matching of pressure data and the second is a pseudo-field example that provides a very rough approximation to a North Sea reservoir in which a realization of log-permeabilities at 9750 gridblocks is computed by the automatic history matching of GOR and pressure data.
A Methodology for History Matching and the Assessment of Uncertainties Associated with Flow Prediction
Authors: Landa Jorge L. , Guyaguler Baris 
Published: December 2007

AbstractAutomatic history matching is the process of calibrating the parameters of a reservoir model by way of an automated algorithm so that the reservoir observations are close to calculated values. Automatic history matching has been heavily investigated, however a fraction of these investigations that provided ways to assess the uncertainties associated with predictions has been computationally prohibitive. In this study an approach based on response surfaces and sensitivity coefficients is presented that is not only a computationally efficient history matching process, but also provides a framework for the assessment of the uncertainties associated with prediction.In this study, sensitivity coefficients are used to construct a response surface or a proxy for the simulator, honoring the exact data values and gradients for the simulated combinations of the parameters. This proxy is then used to guide the selection of the subsequent locations to sample for the history matching process. The accuracy of the proxy increases with the additional simulations as the algorithm progresses. The proxy revealed at the end of the history matching process is then utilized to estimate the uncertainty associated with the predictions of the future performance of the reservoir model.The proposed method is applied to a synthetic well-testing example and a real field case for history matching and uncertainty estimation.
Identifying the Formation Failure Mechanism and Controlling Sand Production from the Upper Tuscaloosa Formation in the East Heidelberg Field Mississippi
Authors: Taylor Brent , Ringhoffer Jay , Jones Ralph 
Published: December 2007

Abstract
Wells previously completed in the upper Tuscaloosa and Christmas Green formations in the Heidelberg Field in Jasper County, Mississippi have exhibited a trend to produce formation sand sometime during their productive lives. Historically, traditional sand control methods have been used to control this sand production.
In order to determine formation failure mechanism, a study using a systematic process had been conducted in completions near Jasper County, Mississippi to determine the failure mechanism. Because of the success in other areas, the same process was used in the upper Tuscaloosa and Christmas Green formations in a four-well field development. The processes not only were capable of confirming the formation-failure mechanism but also were capable of controlling sand production without limiting fluid deliverability in the four wells. From this study, a hypothesis was formulated to determine the cause of formation failure.
The four-well case history will discuss the systematic approach used to confirm the formation failure mechanism and the technology that was then employed to remediate the failure mechanism and to allow these wells to be economically produced.
The discussion will cover eight completions in four wellbores in the East Heidelberg Field. Completion and stimulation technologies will be discussed, including the use of a conductivity enhancement modifier. The effect of the conductivity enhancement and surface modifier on the Upper Tuscaloosa and Christmas Formation will be shown.
The results of the study enabled proper methods to be established to control sand production.
Using Gas Injection for Reducing Pressure Losses in Multiphase Pipelines
Authors: Alvarez Carlos J. , Al-Malki Said S. 
Published: December 2007

Abstract
This paper presents and discusses the results of field testing gas injection into a hilly terrain crude pipeline, and applicable transient multiphase flow simulations. Field testing was conducted to evaluate the effectiveness of using gas injection into a multiphase pipeline operating under severe slugging to reduce pressure losses and increase well rates.
Transient flow simulations were used to predict pipeline pressure losses and select a line for testing. The gas injection method effectively decreased the pipeline pressure about 20 % at the inlet, allowing increased oil production from wells connected to the pipeline inlet. Predicted pressure drop reduction closely matched measurements. The drop in pressure losses is due to reduced liquid holdup in the uphill sections of the line.
Hydrostatic and frictional pressure drops need to be carefully considered to properly operate pipelines under slug flow. Injecting gas into oil pipelines experiencing slug flow can improve oil transport efficiency by reducing pressure losses, increase well rates productivity, and mitigate slug effects on receiving producing facilities. A transient multiphase flow simulator (TMFS) can accurately predict crude oil pipeline pressure drop improvement prior to gas injection.
Producing Coalbed Methane at High Rates at Low Pressures
Authors: Simpson David , Kutas Mike 
Published: December 2007

Abstract
In the highly productive Coal Bed Methane (CBM) "Fairway" area of the San Juan Basin of Northern New Mexico and Southern Colorado, traditional reservoir-evaluation methods have failed to approximate production levels. The reservoir seems to have the potential to produce gas at nearly the same rates at reservoir pressures of under 100 psia as it had at 1,500-1,800 psia. This observation has a significant impact on the economics of late-life investments, on the design of wellbores, on well site equipment, and on pipelines. A non-traditional approach was taken to evaluate the long-term impacts of a mix of these interventions. This mix of interventions was taken and the analysis was generally a fair indicator of specific-well response to the proposed actions.
Calculation Of Permeability Tensor Using Boundary Element Method Provides A Unique Tool To Simulate Naturally Fractured Reservoirs
Authors: Teimoori A. , Chen Z. , Rahman S. S. , Tran T. 
Published: December 2007

Abstract
This paper presents a numerical model to calculate effective permeability tensor in naturally fractured reservoirs. Darcy's law and Navier-stoke's equation are used to formulate fluid flow in rock matrix and fractures, respectively. Fractures of different scales based on their length are considered. Short fractures are considered as an enhancement of matrix permeability by applying the interface boundary condition. Long fractures intersecting more than one block are treated as a source/sink in the corresponding blocks. Fluid flow in porous matrix around the medium and long fractures is modeled by Poisson's equation. Periodic boundary condition is applied on the grid-block boundaries to calculate the elements of effective permeability tensor. The model has been validated against analytical results and applied to a number of cases where arbitrary fractures of different sizes are assumed within the grid-blocks.
New Environmentally Friendly Oil-Based Stimulation Fluids
Authors: DeVine C. S. , Wood W. D. , Shekarchian M. , Hunnicutt B. R. 
Published: December 2007

Abstract
The lab and field development of an environmentally friendly liquid diesel substitute-based (DiSub) system for completion and stimulation, with properties similar to or exceeding those achieved with diesel, will be discussed.
The chemical evolution of the DiSub system and properties of the fluid including rheology, break and conductivity testing, and toxicity data will be presented. The application of the system in a field situation is described.
Since the inception of hydraulic fracturing, oil-based fracturing and completion fluids have been used. Motivations for using these systems include: formation sensitivity to water; water retention by the formation, such as water blocks; and the inability of low-pressure oil productive formations to unload water. Oil-based fracturing designs have historically required complicated procedures to successfully execute a fracturing operation. Fluid compositions used did not consistently produce stimulation fluids with optimum viscosity or transport properties. Drilling and completion activities in the North Sea, deepwater Gulf of Mexico, Alaska, and Canada provided the impetus to develop innovative environmentally-friendly completion techniques and chemistries.
The DiSub system provides a cost effective and environmentally-friendly stimulation fluid. The system is within most global environmental standards and has been approved and used in the North Sea due to its excellent properties, like zero aromatic content, low aquatic toxicity and excellent biodegradability. This makes it a major improvement over the use of diesel and mineral oils, for both humans and the environment. Exposure hazards and the variability of the previously used diesel and/or lease crude are eliminated.
MacKay River SAGD Project Benefits From New Slant Rig Design
Authors: Miller H. , Osmak G. M. 
Published: December 2007

Abstract
Drilling oil sands in the first phase of a steam-assisted, gravity-drilling (SAGD) commercial project in northern Alberta, Canada, presented numerous challenges. The oil sands are too deep for surface mining and too shallow for conventional horizontal drilling. In addition, over-warming these bituminous sands can result in significant wellbore problems.
While conventional slant rig technology could effectively reach the oil sands, the economics of moving the rig between project well sites was not favorable. To improve economics, a new centralized rig design was required that allowed auxiliary drilling equipment to remain stationary while the rig and tubulars moved between wells. A central mud system with specialized cooling and solids control equipment was required to address over-warming of the bituminous sands. The final design also included computer-assisted rig moves, a differential pressure torque monitoring system and floor winches configured to apply pull-down force.
This paper examines the planning process that involved close coordination between the operator and the drilling contractor, and the equipment used in the new rig design. The paper also reviews the drilling of 25 well pairs that allowed completion of the project under budget and four months ahead of schedule.
Mixing Cement by Solids Fraction Instead of Density
Authors: Vigneaux Pierre G , Rondeau Joel , Pathak Rakesh 
Published: December 2007

Abstract
While mixing cement on the fly any density error made may induce large changes in critical slurry properties. Therefore controlling density during a cementing job is known to be one of the key factors to the success of the operation. This led service companies to develop process controlled mixing systems. These equipments work reasonably well when the density of the dry powder – the cement blend – differs significantly from that of the mix water, which is quite often the case.
Blends with engineered particle size distribution have allowed designing cement systems with high performances nearly independently of their density. Recently this technology was upgraded to provide comparable physical properties at slurry density similar to that of water. These new cement blends now have a density that can be equal to that of the mix water. In this case, it is clear that the mixing process cannot be monitored or controlled by measuring the density of the mixed fluid since the mix water, the cement blend and therefore the mixed slurry all exhibit the same density.
To overcome this problem, a new quality control principle based on solids fraction measurement was developed. The first part of this article presents the basic principles of the new device as well as their implementation on existing field equipments. The second part discusses the key advantages of controlling solids fraction and proposes to make it a universal quality control parameter for not only ultra-lightweight high performance slurries, but also for conventional systems be they lightweight or heavyweight. The benefits associated to this new technology are illustrated through the analysis of various cementing jobs while mixing slurries as light as water or at a much higher density.
Use of Vapor Desorption Data to Characterize High Capillary Pressures in a Basin-Centered Gas Accumulation with Ultra-Low Connate Water Saturations
Authors: Newsham K. E. , Rushing J. A. , Lasswell P. M. 
Published: December 2007

Abstract
This paper presents results of a laboratory study of capillary pressure characteristics of core samples from the Bossier sands in the Mimms Creek Field located in Freestone Co., TX. The Bossier tight gas sand play is believed to be part of a basin-centered gas system (BCGS) in the East Texas Basin. Similar to other BCGSs, the Bossier sands are sometimes characterized by an abnormally high capillary pressure profile associated with an ultra-low connate water saturation distribution. We use a vapor desorption technique to measure capillary pressures as high as 10,000 psi and corresponding to water saturations as low as 1%. We also compare capillary pressures measured with a centrifuge and demonstrate our inability to fully define the pressure-saturation range observed in the Bossier sands using a centrifuge.
Reliable Simulation Model Permeability Arrays By Integration of Core, Test, and Log-Derived Permeability Data
Authors: Ghedan Shawket G. , Boyd Douglas A. , Thiebot Bertrand M. 
Published: December 2007

Abstract
The generation of permeability models that best describe the reservoir heterogeneity and its flow dynamics is a difficult objective to achieve. This paper addresses the multi-step procedure followed and the various analytical techniques utilized to integrate different types of permeability data to generate multiple realizations of permeability, which were fed and tested in a dynamic reservoir simulation model for initialization and history matching.
Due to the limited availability of core permeability data and lack of vertical resolution in test permeability data, most modelers rely on statistically log derived permeability predictors to generate permeability models. This paper discusses the design, merits and drawbacks associated with three permeability predictors included in the static geological model of a major carbonate reservoir in offshore Abu Dhabi, along with the rock-typing scheme utilized.
Four analysis techniques are utilized to screen and choose the right permeability predictor for the right sub reservoir or layer of the field. These are merged to generate the first realization of permeability for the simulation model after upscaling.
Test KH conditioned to core KH is taken as a reference in the screening and testing process. The conditioning process is performed at the wells levels to add the core permeability vertical resolution to test permeability data and produce a new log for that matter. This new log is utilized to produce two additional permeability realizations for the simulation model by either conditioning at the wells level followed by modeling and upscaling, or conditioning at the geological model after modeling followed by upscaling.
The initialization of the simulation model is completed with each of the three permeability and rock type realizations. The fluids in place are very close and model is equilibrated. The simulation model performance of the initial history matching runs was found to be very close to the field observed performance for a very complicated and heterogeneous carbonate reservoir. In our case, a combination of the conditioned permeability models are found to be best for achieving a quality history matched simulation model.
Innovative Business Partnership Produces Effective Water Conformance Treatments
Authors: Mitchell W. , Martin A. N. , Stemberger D. , Thayanukulvat P. 
Published: December 2007

AbstractHistorically, water conformance treatments have often proved to be problematic and unreliable. Often, expectations are unrealistic and candidates poor. In addition, wells are treated individually and subsequent unrepresentative results are taken to be the norm. Products or processes that are genuinely effective under the right conditions are often written off as failures, due to ineffective placement or use on unsuitable candidates. However, this does not have to be the case. With proper candidate identification, correct treatment selection and effective treatment placement, water conformance treatments can be placed with a high degree of success.This paper will describe the processes necessary for this to be achieved. These fall into three main stages – candidate selection, treatment selection and treatment execution. Each one of these stages is critical. For the process to work, the right treatment has to be placed at the right point, in the right well. The paper will also detail the care taken in the candidate selection process and illustrate just how critical this is. It will go on to discuss the need for good treatment design and the effective placement of the system selected. The paper will conclude by providing case histories from the offshore Java Sea area, to illustrate just how effective this process can be.