bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Study of Fluid-Flow Mechanism for Cold Production With Sand and Single-Well Fine Numerical Simulation in Heavy-Oil Reservoirs
Authors: Wang Z. , Li S. , Yan C. 
Published: December 2007

Abstract
In order to study the fluid flow mechanism for cold heavy oil production with sand (CHOPS) and predict their production performance precisely, criteria for the skeleton sand erosion and movable sand startup have been set up, based on the stress analysis on formation rock and sand particulates. According to the principles of effective stress, mass conservation, virtual displacement, equivalent virtual work and so on, both the single-well-black-oil model of CHOPS with three dimensions and four phases and the equilibrium equation of borehole wall rock with elasto-plastic deformation have been established. Considering the basic definitions of physical property parameters and the effect on physical property parameters caused by bulk strain, skeleton sand erosion, movable sand deposition on the pore surfaces and movable sand bridge plug at pore throats, dynamic models of physical property parameters have been established for numerical simulation of CHOPS. Then, the coupling solutions of the model have been studied. Finally, a case to verify the correctness and validity of the model is simulated and analyzed. The establishment of the mathematic model describing the fluid flow mechanism of CHOPS is of great significance to help us recognize correctly and exploit heavy oil reservoirs efficiently.
A New Refracture-Candidate Diagnostic Test Determines Reservoir Properties and Identifies Existing Conductive or Damaged Fractures
Authors: Craig D. P. , Blasingame T. A. 
Published: December 2007

Abstract
A new refracture-candidate diagnostic test is presented that requires a brief injection at a pressure exceeding the fracture initiation and propagation pressure followed by an extended shut-in period with the pressure falloff recorded. Provided the time of injection is short relative to the reservoir response, the pressure falloff can be analyzed as a slug test by transforming and plotting the falloff data on a variable-storage, constant-rate drawdown type curve for a well producing from single or multiple finite- or infinite-conductivity vertical fractures in an infinite-acting reservoir. Characteristic variable storage behavior is used to diagnose a pre-existing fracture retaining residual width and to determine if a pre-existing fracture is damaged. Using the proposed model and analysis methodology, a quantitative type-curve/model match can be used to estimate reservoir properties.
In addidtion to the new fracture diagnostic solution, a new single-phase fracture-injection/falloff dimensionless pressure solution is also provided along with new pressure-transient solutions for a well producing from multiple arbitrarily-oriented finite- or infinite-conductivity fractures.
High-Performance, Water-Based Drilling Fluid Helps Achieve Early Oil with lower Capital Expenditure
Authors: Reynolds D. , Popplestone A. , Hodder M. , Gwynne P. , Kelly B. 
Published: December 2007

Abstract
The Forties field was discovered in 1970 and at its peak produced 500,000 bbl of oil per day (bopd). To re-start major drilling operations using oil-based drilling fluids on some of the field's old platforms would have required significant capital expenditure (CAPEX) to ensure total containment of both the fluid and cuttings. An alternative approach on three of the field's platforms has been successfully employed. The first utilisation in the North Sea of a high-performance, environmentally friendly, water-based drilling fluid has helped the operator achieve early oil with much lower CAPEX. It has also proved possible to drill side-track wells through the Eocene overburden and through the reservoir in one hole section. This was not previously considered possible - historically intermediate casing was set and the reservoir drilled with a smaller hole size. Expensive retrofitting of aging platforms to meet environmental obligations for total containment may be unnecessary when a high-performance, water-based fluid is utilised.
This paper describes the characteristics and field performance of this innovative drilling fluid system. Six wells have been drilled from three different platforms during 2004 and early 2005. This paper describes how the fluid performed drilling reactive formations that have only been successfully drilled in the past using oil-based muds. The paper presents a cost model of the alternative approaches to developing Forties using either oil-based muds with total containment or high-performance, water-based fluids with cuttings discharge. This paper will be of interest to Operator's of aging assets looking to continue drilling without heavy CAPEX investment for Total Containment.
Combining Slimhole Rotary-Steerable Technology With Real-Time Geosteering To Rejuvenate a Mature North Sea Field
Authors: Eaton G. , Blasdale T. , Heidenreich K. 
Published: December 2007

Abstract
More than 70% of the oil produced today comes from brownfield environments such as the North Sea. Increasingly complex geological targets demand a more sophisticated and reliable drilling system. The combination of a slimhole rotary steerable system (RSS) and a leading-edge geosteering solution can help operators optimize their well placement. In addition, a Web-based, real-time monitoring and data delivery system can produce the most accurate information possible for decision makers onshore. In this way, an integrated team can use modern logging-while-drilling (LWD) tools to make real- time well path corrections in a challenging environment.
This paper presents a case study in which real-time decisions placed a well successfully and also increased production levels greater than the estimates. The drilling system components responsible for the success were an advanced slimhole RSS,a leading-edge real-time formation evaluation tool, and a Web-based real-time monitoring and data delivery system.
Using Shear-Wave Anisotropy To Optimize Reservoir Drainage and Improve Production in Low-Permeability Formations in the North of Mexico
Authors: Franco J. L. A. , de la Torre H. G. , Ortiz M. A. M. , Wielemaker E. , Plona T. J. , Saldungaray P. , Mikhaltseva I. 
Published: December 2007

Abstract
Shear waves propagate through rock with different velocities in different directions. This phenomenon is called acoustic anisotropy, and it is caused by the anisotropic nature of the rock's elastic properties. All sedimentary rocks exhibit some degree of acoustic anisotropy related to aligned fractures, layering, or stress imbalance. Until recently, wireline sonic tools were able to measure the anisotropy magnitude and orientation reliably only if the velocity anisotropy was greater than 5%. In this paper, we will discuss the field test results from multiple wells of a new sonic tool that is able to measure anisotropy as low as 1%. We will also comment on how to identify the cause of the anisotropy and its applications. Because we can measure the acoustic anisotropy with this new tool—even if it is very low—and relate it to the earth-stress direction, we are able to provide reservoir engineers with valuable information to optimize the field development and improve well production.
The tests were conducted in several Pemex development wells in northern Mexico, mostly in the Burgos basin. The target formations were tight gas sands. The sands have very low permeability and must be stimulated to produce hydrocarbons in commercial quantities. These hydraulically fractured vertical wells have elliptical drainage patterns, and optimum reservoir drainage depends on the correct well placement to avoid creating interference between wells (overlapping drainage areas) or leaving areas untouched (drainage gaps). Since hydraulic fractures open in a plane perpendicular to the minimum stress, determining stress direction is crucial to the placement of new wells. Also, it can help to look for in-field drilling opportunities in brown fields where early drilling strategies did not consider the stress orientation when selecting well locations. In addition, by knowing the stress-field state, it is possible to apply oriented perforating techniques to maximize the results of the fracture treatments.
Parallel Scalable Unstructured CPR-Type Linear Solver for Reservoir Simulation
Authors: Cao H. , Tchelepi H. A. , Wallis J. , Yardumian H. 
Published: December 2007

Abstract
We describe a multistage parallel linear solver framework developed as part of the Intersect (IX) next-generation reservoir simulation project. The object-oriented framework allows for wide flexibility in the number of stages, methods and preconditioners. Here, we describe the specific components of a two-stage CPR1 (Constraint Pressure Residual) scheme designed for large-scale parallel, structured and unstructured linear systems. We developed a highly efficient in-house Parallel Algebraic Multigrid (PAMG) solver as the first stage preconditioner. For the second stage, we use a parallel ILU-type scheme. This new and powerful combination of CPR and PAMG was the result of detailed analysis of the linear system of equations associated with reservoir simulation.
Using several difficult reservoir simulation problems, we demonstrate the robustness and excellent parallel scalability of the IX linear solver. For the field case studies, the IX linear solver with CPR and PAMG is at least five times faster than an established and widely used industrial linear solver. The performance advantage of the IX linear solver over traditional reservoir simulation linear solvers increases with both problem size and the number of processors.
Spontaneous Imbibition with Matched Liquid Viscosities
Authors: Fischer H. , Morrow N. R. 
Published: December 2007

Abstract
Laboratory results of oil recovery through spontaneous imbibition are commonly scaled-up to forecast oil recovery from fractured reservoirs. This study addresses oil recovery from cylindrical sandstone cores by spontaneous imbibition at very strongly water-wet conditions for viscosity ratios of unity (a special case of the Mattax and Kyte scaling condition that viscosity ratios be matched). Combinations of mineral oils and aqueous solutions of glycerol were used to obtain matched viscosities ranging from 4 to 172 cp. In all, 25 imbibition data sets are reported for boundary conditions of all core faces open, two ends closed (radial imbibition), and one end open (linear imbibition). The data sets for individual boundary conditions were satisfactorily correlated by the Mattax and Kyte scaling group. Overall correlation of results was obtained after compensating for different boundary conditions by means of a characteristic length. An obvious limitation of correlations based on linear scaling of time is that differences in the shapes of imbibition curves cannot be eliminated. The correlated data provides clear distinction between the overall shape of recovery curves for linear versus radial imbibition.
Final oil recoveries for radially dominated imbibition were independent of viscosity whereas recoveries for linear imbibition were consistently lower and decreased by up to 2.5 % PV with increase in viscosity. Shortly after the onset of imbibition, oil recovery for linear flow is generally close to linearly proportional to the square root of time until the imbibition front reaches the end of the core.
Deepwater Subsea Valve Flow Assurance—Compatibility Between Hydraulic Control Line Fluids and Completion Brines
Authors: Berry S. L. , Ke M. , Baccigalopi G. 
Published: December 2007

Proposal
Historically, systematic selection of completion brines for conventional completions has been based on several key critieria: hydrostatic density requirements, true crystallization temperature (TCT), pressure crystallization point (PCT), formation compatibility, and compatibility with reservoir fluid systems. However, as the number of deepwater oil and gas completions has increased, new concerns have arisen about the interaction between subsea hydraulic control-line fluids and completion brine systems. In offshore deepwater applications where subsea valves are not readily accessible, ensuring compatibility of hydraulic control-line fluids and completion brine systems is an essential part of the flow assurance process.
Compatibility issues with completion brines become a concern during the initial seating of surface control units such as a subsea wellhead. All the control lines and orifices are filled with hydraulic fluid prior to running in the well to prevent collapse from subsea pressures. After the units are set in position, excess completion fluid has a tendency to displace the control-line fluid or intermix with it. Intermixing of completion brine and hydraulic fluid is critical because many of these fluids circulate through a extremely small orifice (usually less than 3/16 of an inch). Any precipitation of completion brine salts or separation of hydraulic fluid components may result in plugging and loss of hydraulic control.
This paper will discuss and show results of a laboratory study to investigate compatibility between the most widely used water-based hydraulic fluid systems for subsea control applications and a wide range of completion brine systems. Furthermore, since most hydraulic fluids form insoluble solids when mixed with calcium-based brine systems, recommendation of calcium-based completion brines in deepwater applications has been limited. Therefore, a search for a subsea hydraulic fluid system compatible with calcium-based completion brines was conducted. The paper also outlines the results of a study with a subsea hydraulic fluid found to be compatible with calcium-based completion brine systems and discusses the completion advantages of this system.
High-Porosity Fractures Yield High Conductivity
Authors: Parker M. , Glasbergen G. , Batenburg D. van , Weaver J. , Slabaugh B. 
Published: December 2007

Abstract
Fracture conductivity (FC) in many hydraulic-fracturing treatments being performed can be shown to be inadequate. FC is greatly affected by the concentration of the packed proppant in the fracture. Higher concentrations yield higher conductivity by virtue of a wider fracture. However, there are practical limitations to the amount of proppant that can be placed into any particular reservoir and therefore production is often conductivity limited.
An alternate approach to achieve high conductivity is to create a fracture with high porosity. That is, a fracture with porosity much greater than that possible in a packed fracture. This can be achieved by the placement of well-distributed, low-density particles. The low-density particles may be placed in gelled or ungelled treatment fluids. Low particle concentrations are used to achieve the distribution that provides the high porosity in the fracture.
The theoretical basis for the conductivity of these fractures is presented. A three-dimensional model has been developed to simulate the high-porosity fracture created with particles. Test data used to refine the model can be used to help predict the conductivity of the fracture based on the porosity level, the closure stress, and the material mechanical properties.
The Production Success of Proppant Stimulation on Horseshoe Canyon Coalbed Methane and Sandstone Commingled Wells
Authors: Rieb B. A. , Leshchyshyn T. T. 
Published: December 2007

Abstract
North American demand for natural gas has resulted in attractive commodity pricing and thus a renewed interest in unconventional reserve exploration in Canada. Recent activity in Coal Bed Methane (CBM), or Natural Gas from Coal (NGC), has yielded two primary exploration targets that are promising; one of which is the Horseshoe Canyon coal.
The family of Horseshoe Canyon Coals is shallow and range in depths from about 492 ft (150 m) to 2,789 ft (850 m). Even though broadly referenced as Horseshoe Canyon, the stratigraphic range of the coal is from the Edmonton down to the Belly River formations which includes the Horseshoe Canyon formation. These coals are better described as seams or stringers and are most frequently between 1.5 ft and 5 ft in thickness and generally no more than 9.8 ft in thickness. Reservoir pressures at these depths average from 250 psi (1,700 kPa) to 510 psi (3,500 kPa). Production varies due to the commingling of up to 30 stringers per well bore and total well bore production ranges from 35 Mscf/day (1 E3m3/day) to 636 Mscf/day (18 E3m3/day). Horseshoe Canyon coals are generally accepted to be of very low water saturation, low gas production rates and produce little to no insitu water production upon completion.
The most common completion technique is the sequential stimulation of each stringer by the use of coiled tubing. Marginal gas production and intolerance to completion fluids has resulted in evolution of fracturing systems including binary foamed water, CO2 / N2 proppant, conventional borate water, some hydrocarbon based and pure proppantless nitrogen systems pumped at high rates.
Several issues that are dealt with in this paper include concurrent sandstone and coal perforating and stimulation, and a method for comparing coal to coal and coal to sand production. This paper will be used to examine the incremental sandstone contribution to the overall production of the well. Effect of sanding off the well will be examined as to its impact on production.
The objective of this paper is to present findings of an 18 well pilot study in an ongoing 90 well case study completed in a Horseshoe Canyon development near Red Deer, Alberta, Canada. An paper submission is being chosen, and more updated data will be presented at the conference.
A Semiempirical Model To Calculate Wormhole Growth in Carbonate Acidizing
Authors: Buijse M. , Glasbergen G. 
Published: December 2007

Abstract
The success in matrix acidizing carbonate formations depends entirely on the ability to create long wormholes that bypass the damaged near wellbore region. During the last decade, much progress has been made in the understanding of the physical and chemical processes that determine the final wormhole structure. Several different wormhole models have been proposed in literature. These models are usually successful in predicting wormhole growth under idealized conditions in the laboratory: linear core flow tests, one main wormhole, simple fluids like HCl with known rheology and reactivity, etc. In the design of an acid treatment, however, these models are less useful because they cannot handle the complex field conditions such as: radial flow, multiple wormholes, complex fluids such as emulsified acids or foams, etc.
In this paper, we describe an alternative approach to model wormhole growth. A relatively simple wormhole growth model is developed, that still captures the essential physics and chemistry, and is therefore qualitatively correct. The model is semi-empirical, in the sense that the accuracy depends on two parameters that can be measured in a simple (linear) core flow test. Alternatively, the value of these two parameters can be taken from literature data. In developing the model, the intend was to create a relatively simple tool that can be used by the field engineer to design and optimize an acid treatment, and answer basic questions such as: what type of acid must be used and what is the optimum acid volume and pump-rate?
The paper will describe the details of the wormhole growth model. The wormhole model was embedded in a comprehensive near wellbore flow simulator to analyze wormhole behavior in more complex environments, such as multi-layered reservoirs and long horizontal wells. The model has been used with good success in the design of many carbonate acid treatments. Several examples will be discussed in the paper.
A New Experimental Method to Determine Interval of Confidence for Capillary Pressure and Relative-Permeability Curves
Authors: Egermann P. , Lombard J.-M. , Fichen C. , Rosenberg E. , Tachet E. , Lenormand R. 
Published: December 2007

Abstract
The saturation profiles are routinely measured during Special Core Analysis (SCAL experiments). Several ways exist to use this information in the inversion procedure of the relative permeability data. To date, the local saturation profiles are either included in a global objective function that is minimized during the inversion process, or smoothed and used as input data in the simulation, which leads to non smoothed simulated pressure drop. None of these methods permit to reproduce the local saturation fluctuations that are measured during coreflooding experiments. Our approach has the advantage to take benefit from these fluctuations to characterize the petrophysical properties for a given rock-type.
In this paper, the methodology is first recalled and illustrated on a synthetic case. It is based on upscaling techniques applied in reservoir simulation. Both the stabilized and transient saturation profiles are analyzed to evaluate the local properties. The quality of the history matching is significantly improved. In addition, both kr and Pc-curves are obtained from only one experiment and the variability of these parameters with the heterogeneity is also investigated. This estimated interval of confidence for kr and Pc can be very useful to perform uncertainty studies at the reservoir scale.
The Pc-curve interval of confidence determined with this method on a carbonate sample, is in good agreement with the variability observed with several centrifuge experiments performed on sister plugs.
Finally an alternative approach derived of the heterogeneous method is proposed, which allows a very quick acquisition of all the information relative to kr and Pc during a multi-rate flow experiments.