bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimization of Hydraulic Fracture Treatments in The Williams Fork Formation Of The Mesaverde Group
Authors: Ely John. W , Brown Ted. D , Reed Shawn. D 
Published: December 2007

Abstract
An extensive fracturing study has been completed, evaluating over 400 fracture treatments on more than 130 Mesaverde gas wells in the Piceance Basin. This study involved a comparison of many types of fracturing fluids and techniques. Linear gels, foams, energized fluids, titanate crosslinked fluids, zirconium crosslinked fluids and borate crosslinked fluids have all been utilized in stimulating the Mesaverde formation in the study area. The authors evaluated the success of previous treatments which ultimately resulted in stimulation design changes, operational modifications, and expanded quality control methods. Dead strings were utilized on a number of treatments to record static tubing measurements and incorporate into a three dimensional (3D) fracture stimulation model. The modeling work assisted in determining fracture geometry which led to job size changes and revised perforating schemes. This paper will illustrate a number of correlations relating the effect of fracturing fluid viscosity, job size and completion method. Based upon the correlations of the study and the modeling work conducted, Barrett Resources has been able to greatly optimize their fracture treatments from the standpoint of cost effectiveness and enhancement of natural gas production.
Alkaline-Surfactant-Polymer Technology Potential of the Minnelusa Trend, Powder River Basin
Authors: Wyatt Kon , Pitts Malcolm J. , Surkalo Harry , Griffith Lawrence 
Published: December 2007

ABSTRACT
The Alkaline-Surfactant-Polymer, ASP, process can significantly enhance waterfloods for appropriate reservoirs using carefully designed, reservoir specific, chemical injection strategies. This ASP technology recovers waterflood residual oil by reducing the capillary . forces trapping the oil and improving the overall contact efficiency. The Minnelusa formation in the Powder River Basin was the location of the first field-wide application of this process in the U.S. An assessment of this early project nearing the end of its economic life and of other ongoing ASP projects provides an estimate of the potential of the ASP process to add reserves in other Minnelusa fields.
Analysis of approximately 120 Minnelusa oil fields in the Powder River Basin indicates that the total original stock tank oil in place exceeds one billion barrels. The potential incremental oil recovery of the ASP process to these fields approaches 130 million barrels. This process can be applied at an incremental cost of $1.60 -$3.50/bbl.
State-of-the-Art Modeling for Unconventional Gas Recovery, Part II: Recent Developments (1989-1994)
Authors: King Gregory R. , Ertekin Turgay 
Published: December 2007

Abstract
In 1989, a survey of mathematical models which describe methane production from coal seams was presented at the SPE Joint Rocky Mountain Regional/Low Permeability Reservoirs Symposium in Denver, Colorado. This paper was later published in SPE Formation Evaluation Journal March 1991 issue. In this survey, 37 distinct models for coalbed methane production were reviewed in mathematical detail. Since that time, 15 additional mathematical approaches to forecasting reservoir performance, each with its own assumptions and limitations, have been developed. The objective of this paper is to discuss each of these recent models and to compare the assumptions, features, and limitations of these models with each other and with the original 37 models. Recommendations are also presented on the use of each model.
New Step-Rate Test Analysis for Fracture Evaluation
Authors: Lacy L. L. , Hudson H. G. 
Published: December 2007

ABSTRACT
Step-rate injection tests are frequently performed in water injection wells for waterflooding reservoirs and in mini-fracture tests for stimulation treatments designs. In both applications, the data are usually analyzed to determine the fracture propagation gradient. To enhance the usefulness of step-rate test data, the current paper describes a new method of analysis that also determines the injectivity index of the well and fracture, the fracture length, width and effective leak-off rate. Injectivity analysis provides additional formation data which is useful for fracture designs, formation evaluation and optimizing water injection rates. Injection at gradients above the fracture gradient will greatly increase the injectivity of wells as determined by a fracture sensitivity parameter which is determined from step-rate data.
This analysis procedure has been successfully applied to multiple well tests conducted in Alaska and West Texas for waterfloods. In both waterfloods, multiple fracture gradients are indicated by the standard analysis. Injectivity analysis has determined the fracture gradient in both field cases using data from multiple wells. The analysis has also been successfully applied to low-permeability stimulation designs in the Rocky Mountains.
An Integrated Geologic and Engineering Reservoir Characterization of the North Robertson (Clearfork) Unit: A Case Study, Part 1
Authors: Doublet L. E. , Pande P. K. , Clark M. B , Nevans J. W. , Blasingame T. A. 
Published: December 2007

BRIEF SUMMARY
Infill drilling of wells on a uniform spacing, without regard to reservoir performance and characterization, must become a process of the past. Such efforts do not optimize reservoir development as they fail to account for the complex nature of reservoir heterogeneities present in many low permeability carbonate reservoirs. These reservoirs arc typically characterized by:
Large, discontinuous pay intervals Vertical and lateral changes in reservoir properties Low reservoir energy High residual oil saturation Low recovery efficiency
The operational problems we encounter in these types of reservoirs include:
Poor or inadequate completions and stimulations Early water breakthrough Poor reservoir sweep efficiency in contacting oil throughout the reservoir as well as in the near-well regions Channeling of injected fluids due to preferential fracturing caused by excessive injection rates Limited data availability and poor data quality
Infill drilling operations only need target areas of the reservoir which will be economically successful. If the most productive areas of a reservoir can be accurately identified by combining the results of geologic, petrophysical, reservoir performance, and pressure transient analyses, then this "integrated" approach can be used to optimize reservoir performance during secondary and tertiary recovery operations without resorting to "blanket" infill drilling methods.
New and emerging technologies such as cross-borehole tomography, gcostatistical modeling, and rigorous decline type curve analysis can be used to quantify reservoir quality and the degree of interwell communication. These results can be used to develop a 3-D simulation model for prediction of infill locations. In this work, we will demonstrate the application of reservoir surveillance techniques to identify additional reservoir "pay" zones, and to monitor pressure and preferential fluid movement in the reservoir. These techniques are: long-term production and injection data analysis, pressure transient analysis, and advanced open and cased hole well log analysis.
The major contribution of this paper is our summary of cost effective reservoir characterization and management tools that will be helpful to both independent and major operators for the optimal development of heterogeneous, low permeability carbonate reservoirs such as the North Robertson (Clearfork) Unit.
Natural Fracture Characterization Using P-Wave Reflection Seismic Data, VSP, Borehole Imaging Logs, and the In-Situ Stress Field Determination
Authors: Lynn H. B. , Bates Richard , Layman Mike , Jones Mike 
Published: December 2007

ABSTRACT
Seismic data in which anisotropy is observed have been used to detect and characterize the natural fractures, in the Bluebell-Altamont, Utah, field. We show an (azimuth-dependent) amplitude variation with offset (AVO) anomaly in the P-wave reflection seismic, attributable to the gas-filled vertical oriented fractures, and substantiated by the 9-component VSP.
Characterization of a Delaware Slope Basin Reservoir for Optimal Development
Authors: Weiss William W. , Ouenes Ahmed , Sultan Ahmad J. 
Published: December 2007

Abstract
A reliable reservoir description is essential to investigate various scenarios for successful field development. In this study, various new tools have been applied to fully characterize the East Livingston Ridge Delaware reservoir.
The Delaware formations in their slope/basin environment are difficult to characterize due to the channels in the submarine fans. Using well logs, a complex 3-D reservoir model composed of a channel through the bottom three layers of a seven layer model with one non-oil bearing zone was constructed to represent this complex depositional setting. Drastic changes in layer lithologies resulting in multiple oil/water contacts and varying water saturations required detailed log interpretation.
The porosity logs were tuned with available sidewall core information. Log porosity was determined for each layer at each well and kriging was used to estimate the areal distribution of the porosity. Porosity- permeability correlations for each layer were developed from sidewall core data. The correlations were used to make an initial estimate of the interwell permeabilities. A production history match was not possible with the initial characterization of the reservoir.
The production rates of the oil, gas, and water phases of each of the twenty-three wells in the East Livingston Ridge field and the pressure data were automatically history matched using a recently developed simulated annealing technique. The absolute and relative permeabilities of the layers were varied automatically during the history matching phase of the reservoir study. The larger scale properties resulting from the calibrated model were used to forecast the results of continued primary, infill drilling and/or waterflooding.
Engineering Criteria for Fracture Flowback Procedures
Authors: Barree Robert D. , Mukherjee Hemanta 
Published: December 2007

Abstract
Post treatment fracture flowback procedures during closure are often critical to the retention of fracture conductivity near the wellbore. Postfrac production performance largely depends on this conductivity. The importance of proper flowback procedure has been documented in the fracture industry, but definitive guidelines for flowback design have never been established. As a result, many misconceptions exist regarding the physics of proppant flowback and its effects on the final proppant distribution in the fracture.
This paper presents a rigorous study of fracture flowback and proppant migration during closure using a fully three-dimensional fracture geometry simulator (GOHFER). The effects of rate of flowback, location of the perforation interval, final proppant concentration, and the fracture geometry prior to flowback on the retained post closure proppant concentration are discussed. Consideration is given to the fluid velocity field in the created fracture resulting from the flowback, and its effects on proppant movement and localized fracture closure. These studies illustrate the difference between "forced closure" and "reverse screenout" concepts in flowback design. Other effects such as crossflow between multiple perforated layers are also studied. Simulation studies indicate that selection of a desirable flowback rate is very sensitive to crossflow effects resulting from induced fractures in multiple stress layers. This crossflow can result in significant overflushing of proppant in the lower stress zones, if not countered by properly applied flowback procedures. Very high flowback rates, exceeding the total leakoff rate, may be needed to avoid such overflushing.
The results of this study are assimilated into a set of recommendations for optimum flowback design leading to the maximization of the near-wellbore fracture conductivity and maximum attainable conductive length in communication with the perforations. Ideally, any properly applied controlled flowback procedure should induce a reverse screenout at the wellbore - forcing closure on the proppant by packing the near-wellbore area, not by depleting fluid pressure and "pinching" the fracture closed.
Imaging Hydraulic Fractures Using Temperature Transients in the Belridge Diatomite
Authors: Shahin G. T. , Johnston R. M. 
Published: December 2007

Abstract*
Results of a temperature transient analysis of Shell's Phase I and Phase II Diatomite Steamdrive Pilots are used to image hydraulic injection fracture lengths, angles, and heat injectivities into the low-permeability formation. The Phase I Pilot is a limited-interval injection test. In Phase II, steam is injected into two 350 ft upper and lower zones through separate hydraulic fractures. Temperature response of both pilots is monitored with sixteen logging observation wells.
A perturbation analysis of the non-linear pressure diffusion and heat transport equations indicates that at a permeability of about 0.1 md or less, heat transport in the Diatomite tends to be dominated by thermal diffusivity, and pressure diffusion is dominated by the ratio of thermal expansion to fluid compressibility. Under these conditions, the temperature observed at a logging observation well is governed by a dimensionless quantity that depends on the perpendicular distance between the observation well and the hydraulic fracture, divided by the square root of time. Using this dependence, a novel method is developed for imaging hydraulic fracture geometry and relative heat injectivity from the temperature history of the pilot.
The azimuth of the Phase I hydraulic fracture is determined to be 14 ± 2° N-NE. The azimuth of the Phase II upper hydraulic fracture is determined to be 16 ± 2 ° N - NE in the northern half of the pilot, increasing to 21 ± 2° in the southern half of the pilot. The azimuth of the lower hydraulic fracture averages 19 ± 4°. The hydraulic fractures are found to be symmetric around both injectors with an estimated length of 200 ft.
Increased steam injection after the first year of pilot operations caused what is interpreted to be horizontal fractures toward the west in the G cycle and the east in the M cycle. These features are imaged to be at least 100 ft and 160 ft along the hydraulic fracture azimuth.
These conclusions are compared to tiltmeter data, microseismic data, and a simulation history match of pilot performance. Microseismic events recorded in the pilot are apparently not diagnostic of heat delivery to the formation.
Optimizing Steamflood Performance Utilizing a New and Highly Accurate Two-Phase Steam Measurement System
Authors: Huff B. D. , Warren P. B. , Whorff F. M. 
Published: December 2007

ABSTRACT
A new highly accurate steam measurement system has been developed for the measurement of steam quality and flow rate. This system consists of a "V" cone (differential pressure device) and a vortex meter (velocity device) in series, along with temperature and pressure sensors all interfacing with an electronic datalogger. These basic mechanical meters are both rugged and relatively inexpensive for field monitoring purposes. Tests performed in active steam drive projects prove the viability of this system. As a result, every injector in the Coalinga field (around 100 steam injectors) has been economically justified for utilizing this new technology. Ever since the application of steam for commercial EOR operations, the petroleum industry has been searching for a method to determine both steam quality and flow rate for monitoring, analyzing and optimizing steam drive projects. This paper p00000000resents an overview of the new system, the background and development work that has been completed to date, and the reservoir analysis and economic justification required to implement this project.
Project Design for Slimhole Steam Injectors in Thermal Recovery Projects as Compared to Conventional Steam Injectors
Authors: Dennis E. L. 
Published: December 2007

ABSTRACT
Slimhole injection technology has been used since early 1992 in San Joaquin Valley steamfloods. The major advantages of slimhole injectors over conventional injectors are: (1) low initial capital cost, (2) ability to place wells at optimum locations, (3) improved injection profile, (4) ease with controlling steam breakthrough in individual sands, and (5) low cost access to bypassed oil. There also are disadvantages: (1) limited injection rates and limited downhole survey or remedial work, (2) increased wellbore heat losses, and (3) increased potential for thermal stress- related casing failure.
This paper details advantages and disadvantages of slimhole injectors over conventional injectors and discusses design parameters that must be considered for successful implementation of slimhole injectors.
Testing and Production Performance of Slim-Hole Wells
Authors: Azari Mehdi , Soliman Mohamed , Wendler Curtis 
Published: December 2007

Abstract
The petroleum industry is focusing on cost reduction and efficiency more than it ever had. Slim-hole drilling and completion technology offer significant cost reduction potentials to the oil and gas industry. To provide an insight into slim-hole technology, production, stimulation, conformance, perforation, and testing aspects of reservoirs with wellbore and completion string diameters of less than conventionally drilled and completed wells are detailed here.
Productivity of both horizontal and vertical slim-hole wells, with and without hydraulic fractures, is compared with wells having standard wellbore sizes. Comparisons with conventional sized wellbores will be given that concern; 1) wellbore hydraulics, including nodal analysis and minimum gas rates required to lift fluids off the well, 2) the effect of wellbqre diameter on transient pressure testing, and 3) coning and cresting problems.
The performance of slim-hole wells compares favorably to standard wellbore completions for the parameters investigated in this study.
Economic Disposal of Solid Oil Field Wastes through Slurry Fracture Injection
Authors: Bruno M. S. , Bilak R. A. , Dusseault M. B. , Rothenburg L. 
Published: December 2007

Abstract
A variety of solid oil field wastes, including produced sand, tank bottoms, and crude contaminated soils from old well cellars and tank farms can be economically disposed of in an environmentally acceptable manner through slurry fracture injection (SFI). Solids are mixed into a slurry with fresh or produced water and injected at high pressure into suitable sand formations. The carrying fluid bleeds off rapidly, leaving behind a pod of solid wastes entombed by the natural earth stresses. High fluid leakoff allows more efficient creation and packing of short wide fractures.
At shallow to moderate depths, in-situ stresses may be sufficiently modified to establish horizontal fractures and allow periodic disposal of large quantities of solids - on the order of tens of thousands of cubic yards; With proper process design and monitoring, fracture growth can be Carefully controlled and contained within the target interval.
The slurry fracture injection process has been successfully applied to dispose of large quantities of oil saturated sands and tank bottoms in Alberta and Saskatchewan, Canada. This technique offers a number of economic and environmental advantages for disposal of solid oil field wastes. When reinjecting into depleted oil sands, the crude waste is simply being returned to its place of origin. The long term liability to the operator is eliminated, in marked contrast to surface storage or landfill disposal. Finally, for moderate to large quantities of solid waste fracture injection costs are less than typical transport and landfill disposal costs.
Computer Simulations of Proppant Transport in a Hydraulic Fracture
Authors: Unwin A. T. , Hammond P. S. 
Published: December 2007

Abstract
The equations of motion of a slurry in a narrow slot, such as a hydraulic fracture, are presented and solved numerically to obtain an estimate of the amount of gravity-driven vertical motion of proppant that can occur within a fracture during placement.
Two types of gravity-driven motion are studied: settling of heavy proppant particles; and convective proppant transport, which refers to the motion driven by large-scale density differences between regions of different proppant concentration.
Computer simulations are performed using realistic parameter values. In particular, we compare the vertical motion of proppant in a slurry in which the proppant particles are uniformly distributed across the fracture width (referred to as homogeneous flow) with that in a slurry in which some unspecified, but rapid, process has caused all the proppant to migrate across the fracture width into a close-packed sheet at the fracture centre (referred to as sheet flow).
In addition to considering a constant channel width, we also investigate the effects of an elliptic fracture cross-section on proppant placement. This fracture shape is predicted by idealized fracture propagation models such as the PKN model.
The main conclusions are that during placement Proppant settling and convection can occur under practical conditions.Convection rates are slightly greater in sheet flow than in homogeneous flow, and settling is greatly enhanced in sheet flow. Overall, settling in sheet flow gives the worst vertical motion of proppant. Settling and convection in homogeneous flow cause no problems under the conditions considered in this paper.In elliptic fractures, heavy proppant-laden slurry can over-ride earlier pumped lighter pad (zero solids) under most fracturing conditions.
Steam Management in Composite Mature Steam Floods, Midway Sunset Field
Authors: van Dorp J. J. , Roach R. H. 
Published: December 2007

ABSTRACT
Vogel1 noted that oil production rates in many steam floods are not predictable from steam injection rates and must be estimated on some other basis. He presented a conservative method, based on simple models assuming instantaneous steam overlay, to calculate heat requirements once the oil rate is known. By more accurately describing the reservoir being flooded and the steam flood process, Vogel's method was refined resulting in significant steam savings for SWEPI's leasehold in the northern part of the Midway Sunset field. Analytical expressions are presented for 1) the heat required to support a steam chest descending into an oil column, 2) the heating of a cap or base rock already partially heated by an adjacent steam flood and 3) die heating of a cap or base rock which is exposed to a uniformally growing steam zone. A method is also described to operate a mature steam flood at a constant oil steam ratio while scavenging some heat stored in the steam zone.
Utilizing WASP and Hot Waterflood to Maximize the Value of a Thermally Mature Steam Drive in the West Coalinga Field
Authors: DeFrancisco S. T. , Sanford S. J. , Hong K. C. 
Published: December 2007

ABSTRACT
The Water-Altemating-Steam-Process (WASP) has been utilized on Section 13D, West Coalinga Field since 1988. Originally implemented to control premature, high-temperature steam breakthrough, the process has improved sales oil recovery in both breakthrough and non-breakthrough patterns.
A desktop, semi-conceptual simulation study was initiated in June 1993 to provide a theoretical basis for optimizing and monitoring the WASP project. The simulation study results showed that the existing WASP injection strategy could be further optimized. It also showed that conversion to continuous hot waterflood was the optimum injection strategy for the steamflood sands.
The Section 13D WASP project was gradually converted to hot waterflood during 1994. Conversion to hot waterflood has significantly improved project cash flow and increased the value of the Section 13D thermal project.