bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of a Calibrated Fracture-Growth Model and Automated Staging Routine for the Jonah Field
Authors: Malone Scott , Turner Mark , Mayerhofer Mike , Northington Neill , Weijers Leen 
Published: April 2009

Abstract
One of the most important challenges in the Jonah Field in Sublette County, Wyoming, is to obtain effective fracture-height coverage over the entire 2,800+ ft Lance formation. The Lance formation in Jonah Field is composed of a stacked sequence of 20 to 50 fluvial channel sands interbedded with associated overbank siltstone and floodplain shale deposits. Within this interval, the net-to-gross ratio varies from 25 to 40%. Sandstone bodies occur as individual 10- to 25-ft thick channels and stacked-channel sequences greater than 200 ft in some cases.
Tiltmeter and microseismic fracture mapping was conducted on hundreds of propped-fracture treatments in the Jonah Field. These direct height-growth measurements helped to obtain an understanding about the effectiveness of shale barriers. It was found that a standard triple-combo log suite could be used to identify shale barriers for fracture growth.
A calibrated fracture model was developed for the Jonah Field that ties the log analysis to the fracture-growth behavior that was mapped using direct fracture-mapping technologies and to the net-pressure response measured during propped fracture treatments. These improvements in predictive modeling capabilities have lead to better insight into fracture growth behavior in the Lance formation.
A 3D fracture-growth model was modified to determine perforation strategy and fracture-treatment schedules to obtain effective coverage of the Lance formation in new Jonah wells in a semi-automated process. As a result, the entire process for fracture design can now be performed in an integrated software package.
Evaluating the Performance of Hydraulically Fractured Horizontal Wells in the Bakken Shale Play
Authors: Tabatabaei M. , Mack D. , Daniels R. 
Published: April 2009

Abstract
In the last several years, interest in developing unconventional oil and gas reservoirs has grown tremendously. Most of these unconventional reservoirs have very low permeability which makes them unable to produce at economic flow rates without massive stimulation treatments or special recovery processes. Bakken Shale play is one of these reservoirs which horizontal wells with hydraulic fracture treatments have been proven to be an effective method for its development. In this study, to evaluate the performance of hydraulically fractured horizontal wells in the Bakken Shale play, a rigorous analytical model has been developed to predict the productivity of a tight multi-layered reservoir drained by a horizontal well with a longitudinal fracture. This model rigorously couples flow in the matrix to flow in the fracture, and then to flow in the wellbore to account for the fracture conductivity and wellbore hydraulics, respectively.
History matching of production data for Bakken wells reveals that the developed model provides a reliable tool for predicting the productivity of this type of well-reservoir configuration. Moreover, using this model to study the key factors influencing the well performance indicates that length of fractured portion of the lateral is the primary factors affecting the well productivity, while conductivity of fracture has an insignificant effect on productivity, which means using better proppant or fluid has minimal effect on productivity.
Analytical Solutions for the Radial flow Equation with Constant-Rate and Constant-Pressure Boundary Conditions in Reservoirs with Pressure-Sensitive Permeability
Authors: Friedel Torsten , Voigt Hans-Dieter 
Published: April 2009

Abstract
The transient pressure response in stress-sensitive formations is derived by solving analytically the radial flow equation with pressure-dependent rock properties. New solutions are obtained for slightly compressible fluids and real gas flow with constant-rate and constant-pressure wellbore boundary conditions using the Boltzmann transformation. In particular in low-permeability formations, a sensitivity exists to pore pressure changes. Permeability there normally declines with the increase of effective stress. The mathematical model presented here takes into account the reduction in permeability caused by an increase in effective stress for two common parameterized pressure-permeability functions, i.e., a linear and an exponential relationship. The analytical solutions are verified with numerical simulation. They are applicable for well test analysis and prediction of flow rates, as demonstrated in this paper.
Advancing Reservoir Simulation Capabilities for Tight Gas Reservoirs
Authors: Abacioglu Yafes , Sebastian Herbert M. , Oluwa Jubril B. 
Published: April 2009

Abstract
It is critical to identify optimum well spacing to develop cost-effective full field development plans for tight gas reservoirs. Accurate prediction of well performance is a major challenge that arises during the development of such reservoirs. Understanding well performance is needed for both well design and depletion planning. Almost all wells in tight gas fields are hydraulically fractured. We have investigated methods of simulating hydraulic fractures using coarse grids since explicitly gridding these fractures can easily lead to an impractical number of grid blocks for large, full field models with many and complex wells.
We have developed practical solutions for accurately representing both flowing and shut-in performance of hydraulically fractured vertical wells and multiply fractured horizontal wells in full-field models. We have validated these approximations in trials with actual field examples.
We found it necessary to enable wellbore cross-flow in the simulator for coarse grid field-scale models to more accurately simulate observed shut-in pressures. We also found differences in pressure distribution results of finite difference simulation between models using a pressure formulation vs. those using a pseudo-pressure formulation when simulating tight gas reservoirs under certain conditions.
In summary, the existing commercial reservoir simulation tools can be adapted to model challenging tight gas depletion scenarios and optimize well spacing. However, care must be taken to ensure that the models are properly constructed and results frequently checked for consistency.
An Effective Model for Pipe Friction Estimation in Hydraulic Fracturing Treatments
Authors: Barree R. D. , Gilbert J. V. , Conway M. W. 
Published: April 2009

Abstract
An adequate model of pipe friction and fluid hydrostatic head is needed to allow understanding of bottomhole treating pressure trends during pumping. Models currently used by service providers appear to be inadequate, based on observation of field bottomhole treating pressure (BHP) plots. A new model is provided which has been extensively tested for gelled fluids, foams, and slick-water fracs. The model predictions are compared to direct measurements of BHP during typical high-rate treatments in various pipe sizes.
Use of an adequate pipe friction model improves analysis of stimulation treating pressures and allows better decisions to be made regarding on-the-fly design changes and post-job interpretations of created fracture geometry and resulting conductivity. The paper presents a useful model for the estimation of pipe friction, slurry head, and surface treating pressure during hydraulic fracturing treatments.
Estimates of Potential CO2 Demand for CO2 EOR in Wyoming Basins
Authors: Wo S. , Whitman L. D. , Steidtmann J. R. 
Published: April 2009

Abstract
A database of Wyoming oil reservoirs is developed to identify candidate reservoirs suitable for miscible or immiscible CO2 flooding, a method that has already proven to be a viable enhanced oil recovery process at Lost Soldier, Wertz, and Salt Creek fields in Wyoming. Based on the CO2 usage of existing CO2-EOR projects in Wyoming and other regions, the initial and total CO2 demands are estimated for the identified reservoirs and grouped by basins. The simple formulas presented in this paper provide a quick estimation of the required initial and total CO2 volumes with specified reservoir parameters. Wyoming has produced about seven billion barrels of oil from more than 1200 oil producing fields. 98% of the oil was produced from the top 400 fields, evaluated in this study, each with a cumulative production exceeding one million barrels of oil. More than 500 oil reservoirs, by passing either miscible or immiscible screening criteria, are identified as potential CO2-EOR candidates. Large fields often have multiple oil producing reservoirs suitable for CO2 flooding. It is estimated that 1.2 to 1.8 billion barrels of additional oil might be recovered by CO2 flooding and up to 20 trillion cubic feet of CO2 could be sequestrated after CO2 EOR in Wyoming's oil basins.
Haynesville Shale-Petrophysical Evaluation
Authors: Parker Mark , Buller Dan , Petre Erik , Dreher Doug 
Published: April 2009

Abstract
The Haynesville Shale is an unconventional gas reservoir located in east Texas and northwest Louisiana. High gas prices and the success of other shale gas plays have led operators to invest highly in this unconventional reservoir. It has great potential for development by applying all the new technology that is available in the oil and gas industry today.
Petrophysical evaluation of reservoirs has long been used for exploration and reserve estimates. New logging tools and analysis techniques have been developed to provide more precise data about target zones and bounding layers that are important when considering hydraulic fracturing for unconventional reservoirs.
A processed log interpretation calibrated for the Haynesville Shale is computed using a typical triple-combo suite of logs. Other log data, such as borehole imaging, magnetic resonance, dipole sonic, and spectral gamma ray, will improve and verify the interpretation. Core analysis provides accessory data on mineralogy, total organic carbon (TOC), and rock mechanical properties to calibrate this processed log computation and improve the accuracy of the total shale interpretation.
Identification of the following reservoir characteristics provides the starting point for completion-and hydraulic-fracture stimulation design: Identification of free-gas zonesIdentification of rock types and mineralogyTotal organic contentQuantification of effective shale porosityEstimates of shale permeabilityMechanical stress measurement for hydraulic-fracturing designIdentification, classification, and orientation of marginal-class, open-conductive, and drilling-induced fractures
A number of Haynesville Shale examples are presented to highlight all interpretation techniques and variations in the shale itself within its proven productive area. This interpretation can be critical for the hydraulic-fracture design approach for the Haynesville Shale.
A Simple Method to Account for Permeability Anisotropy in Reservoir Models and Multi-Well Pressure Interference Tests
Authors: Yetkin C. , Ramirez B. , Al-kobaisi M. , Kazemi H. , Ozkan E. 
Published: April 2009

Abstract
Permeability anisotropy, via full permeability tensor, has not been accurately accounted for in reservoir models because of the implementation complexity. Specifically, numerical implementation of the off-diagonal components of the permeability tensor is inconvenient and cumbersome. This paper shows how directional permeability, calculated from a full permeability tensor, can be used as a simple replacement both in coding numerical models and in day-to-day engineering analysis. For the former, we have implemented the directional permeability for single-phase flow in a 9-point finite-difference formulation, which is easy to code. This formulation, however, is easily applicable to any control-volume formulation including the perpendicular bisector (PEBI) grid. The implementation of this technique has produced excellent numerical results in numerical simulation of multi-phase flow displacement. For routine engineering applications, we have also applied this technique to generate pressure responses for a four-well interference test in a highly anisotropic system. The analysis of the test results by conventional type-curve matching produced the correct reservoir geometric-average permeability and a very good approximation for the direction of the maximum permeability, which is a testimony to the credibility of the formulation. The use of this formulation should be very useful in determining major natural fracture trends in reservoirs undergoing water or gas injection, and in modeling fracture trends in other fractured reservoir situations, such as tight sands.
Exponential Growth in San Juan Basin Fruitland Coalbed Permeability With Reservoir Drawdown—Model Match and New Insights
Authors: Shi J. -Q. , Durucan S. 
Published: April 2009

Abstract
The exponential growth behaviour of coalbed permeability with reservoir pressure depletion has previously been observed at the Fairway wells in the San Juan Basin. More recently the exponential trend has also been confirmed for a group of 10 wells in a region NE of Fairway. Increase in the absolute permeability of coalbeds is a result of matrix shrinkage caused by gas desorption, which becomes a dominant factor on cleat permeability over the effective stress effect during reservoir production.
A permeability model previously developed by the authors has been re-visited in an effort to match the recently published field permeability data. The Shi and Durucan permeability model makes use of a stress-permeability relationship reported in the literature for an idealised geometry (matchsticks), in which the permeability varies exponentially with changes in the effective horizontal stress through the use of a cleat (pore) compressibility parameter. In this study, a stress-dependent cleat volume compressibility defined by an initial compressibility with a negative exponential decline rate was adopted. By tuning these two parameters, it was possible to achieve a close match to all the field permeability data by using a common set of reservoir properties (elastic properties and matrix shrinkage parameters) that are consistent with the available field and laboratory data in the literature.
The matching of the field permeability data in these two regions of the San Juan Basin has further validated the Shi and Durucan permeability model (with variable cleat volume compressibility). It has also provided theoretical support for the observed near-exponential growth behaviour of coalbed permeability in a producing reservoir. Furthermore, the model has shed new insights into the permeability behavior: 1) the exponential growth occurs when the reservoir pressure is reduced to a level generally below the permeability recovery pressure (the reservoir pressure at which the initial permeability is recovered); 2) the reservoir permeability in these two regions would remain relatively flat at reservoir pressures above the permeability recovery pressure.
Well Production Forecast in a Tight Gas Reservoir—Closing the Loop With Model-Based Predictions in Jonah Field, Wyoming
Authors: Iwere F. O. , Gao H. , Luneau B. 
Published: April 2009

Abstract
This paper presents a closed-loop reservoir study in tight gas fluvial sands of the giant Jonah gas field located in the northwestern part of the Greater Green River Basin, Wyoming. It produces gas from the micro-darcy fluvial channel sandstones of the Upper Cretaceous Lance Formation after multistage hydraulic fracturing. Single sand body pay zones would not be commercially attractive.
Rigorous reservoir modeling and simulation workflows were employed to build a 3D flow model from geology, geophysics, petrophysics and engineering data and interpretation. The stacked, multi-pay, tight gas sandstone reservoirs and their overpressured conditions were modeled and the hydraulic fractures properties were derived from matching initial well performance. The model was calibrated with well and field performance data through 2006. The calibrated model was used to forecast well performance, estimate reserves; investigate optimal well spacing and infill-well patterns.
Production for old wells and infill wells completed during 2007 and 2008 which was not included in the model calibration is compared with our previously forecasted results. The comparison shows that the actual well production of most of the wells is close to our forecasted results. The production-validated results of this closed-loop study clearly demonstrate that well production and field performance can be forecasted using reservoir modeling and simulation in a highly heterogeneous reservoir. Rigorously-constructed reservoir model(s) help us test and determine optimal production techniques to maximize field production goals. It can be confidently used to reduce field development risk and maximize profits.
Controlling Bacteria in Recycled Production Water for Completion and Workover Operations
Authors: Tischler A. , Woodworth T. R. , Burton S. D. , Richards R. D. 
Published: April 2009

Abstract
Reusing flowback water and produced water from active wells becomes more and more important in today's oil and gas operations to control surface water volumes in order to keep surface water disposal costs (reinjection or trucking off the premises) to a minimum – especially in operations that do not require secondary lift support. However, reusing untreated produced and flowback water untreated in workover and completion operations can promote bacteria growth both above and below ground.
Water produced from oil and gas wells is a perfect environment for sulfate reducing bacteria (SRB) and acid forming bacteria (AFB) due to its anaerobic nature (&lt; 2ppm O2 content) and high nutrients content (organics, free iron, etc.). Reuse of water introduces enough oxygen through regular pumping operations to allow aerobic bacteria to grow – mostly slime forming bacteria (SFB). The oxygen content is high enough for aerobic bacteria to grow but too low to kill anaerobic bacteria. The oxygen content will cause the anaerobic bacteria to stay in a biostatic state which does not kill them but prevents them from multiplying.
As soon as the bacteria find an environment that is conducive to their growth, they will become active again and start multiplying. The anaerobic environment in the formation is ideal for growth of bacteria like SRBs and AFBs. The aerobic environment of the wellbore is conducive for SFBs. The growth of SRBs will not only lead to Health and Safety (H&S) concerns due to increased sour gas or hydrogen sulfide (H2S) production but also to a slow souring of the formation. This also increase operation expenses due to added corrosion (H2S pitting, stress cracking etc) in surface and subsurface tubulars and related prevention expenses. Other challenges in production can be related to AFBs (pitting) and SFBs (emulsion like materials may form).
Various different methods can be applied to prevent bacteria growth and reduce operational expenses related to corrosion prevention, remediation of corrosion effects, and remediation of emulsion like produced fluids. This paper will take a closer look at the methods of aeration, chlorine based applications (sodium hypochlorite, calcium hypochlorite, and chlorine dioxide), and biocide application.
The different methods will be compared through laboratory tests, actual field application, and a rating system. The rating system incorporates environmental, health, and safety (EH&S) concerns, operational application/considerations, effectiveness of the method, and cost.
Each method will be discussed and the pros and cons presented. The pros and cons will be supported by laboratory and field data. The conclusion portion of the paper will give reasoning on why and how the current method of application was chosen and discuss future improvements and testing.
Maturity and Impedance Analyses of Organic-Rich Shales
Authors: Prasad Manika , Mba Kenechukwu C. , Elizabeth McEvoy T. , Batzle Michael L. 
Published: April 2009

Abstract
Organic-rich shales (ORS) need to be studied in detail to understand the provenance and the generation of oil from source rocks. In recent years, ORS have become interesting as important hydrocarbon resources as well. Successful exploration and production programs for ORS need reliable identification of the kerogen content and the maturity through indirect seismic methods. However, the seismic properties of kerogen are poorly understood and so, predictions about maturity and rock-kerogen systems remain a challenge. Assessment of maturity from indirect measurements can be greatly enhanced by establishing and exploiting correlations between physical properties, microstructure, and kerogen content.
In this paper we show correlations between the impedance microstructure of ORS and their maturity and elastic properties. We have used scanning acoustic microscopy to analyze and map the impedance microstructure in ORS. We quantified textural properties in the images and related these textural properties to maturity and to impedance from acoustic wave propagation measured at centimeter scales. This combined study of acoustic and microstructures of ORS give important insight in changes due to kerogen maturation. We introduce a modified porosity term and find that (i) there is a significant correlation between velocity and modified porosity of all ORS; (ii) Imaging and quantifying microscale impedance texture and contrast in the images allows us to correlate them with ultrasonic measurements on a cm-scale; and (iii) textural heterogeneity, elastic impedance, velocity, and density increase with increasing shale maturity.
In this paper, we show typical acoustic images of ORS and discuss possible methods to predict maturity from impedance based on understanding the changes due to maturity in well log response, core measurements, and microstructure of organic-rich shales. Our work has important bearing on developing successful production and stimulation methodologies.