bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Unconventional But Definitive Analysis of a Field's Production Improvement
Authors: Schulz R. , Harms L. 
Published: October 2008

Abstract
Production results from capital or operational investments are often difficult to identify and quantify due to a field's decline and other factors that introduce noise in the data. This was the case with a series of operational improvements in a tight gas field of 80 mostly marginal wells located in South Texas, a mature producing area similar to Appalachia's assets.
However, approaching the problem with a set of statistical tools not commonly applied in the upstream oil and gas industry yielded a definitive answer to the success of the investments. Normal distribution analysis and hypothesis testing are well-grounded academically and have been applied in globally competitive manufacturing operations for decades, but are not common tools in the petroleum engineer's toolkit. Nevertheless, today's low-cost, easy to use statistical software facilitates an easy transition to the oil and gas industry.
The results from using the above methods eliminated uncertainty about the success of the operational changes, which was questionable using traditional production and decline curve analysis. In addition to proving the success of the investments, the model also points to the viability of improvement by reducing production variation as opposed to looking exclusively for production increases.
These statistical methods are especially significant for analyzing data, particularly in marginal, mature producing areas. Moreover, the analytical methods can yield definitive answers to a number of oil and gas engineering, operation, production and financial questions. Hence, one will be able to take the material provided and leverage it to help in a number of potential applications.
Simulation of Gel Damage on Fracture Fluid Cleanup and Long-Term Recovery in Tight Gas Reservoirs
Authors: Wang John Yilin , Holditch Stephen A. , McVay Duane A. 
Published: October 2008

Abstract
One major source of new natural gas supplies for the world will be gas from low permeability reservoirs. Currently, natural gas from tight sandstones, carbonates, coal seams and shales account for over 25% of the annual gas production in the United States. Global production of gas from similar reservoirs world wide will be expected in the next few decades. For such reservoirs, the wells have to be successfully fracture treated to produce at commercial gas flow rates.
In many situations, the created length was probably achieved, and maybe even the propped length was achieved. However, due to insufficient proppant concentration, or insufficient proppant transport, or the use of the wrong propping agent, or a fracture fluid that does not break to a low viscosity fluid, the effective fracture length is significantly less than the designed length and does not provide optimal production results.
It is our opinion that insufficient fracture fluid cleanup is the primary cause of poor results when the optimal effective fracture length is not achieved. Fracture fluid cleanup is affected by gel damage, which includes the static yield stress, the flowing yield stress, the amount of polymer residue in the fracture after the fracture closes, and the amount of polymer that forms a filter cake on the walls of the fracture. In addition, there are other issues such as proppant crushing and non-Darcy flow effects that also affect fracture fluid cleanup.
In this research, we have used a reservoir simulator to model how polymers in the fracture affect fracture fluid cleanup. We have incorporated mathematical expressions for static yield stress. We have included the effects of proppant crushing, gel residue plugging and the formation of a filter cake on the clean up behavior and the resulting gas flow rates. With our model, we are able to simulate many of the problems we observe in field data and problems documented in the petroleum literature. Even though real solutions to these problems still remain to be developed, we think we can explain the issues behind most fracture fluid cleanup problems and offer a few ideas on what can be done to solve them.
Hydraulic-Fracture Modeling With Bedding Plane Interfacial Slip
Authors: Gu H. , Siebrits E. , Sabourov A. 
Published: October 2008

Abstract
Interfacial slip is one of the mechanisms that can alter the growth of a hydraulic fracture when it encounters weak planes or natural fractures. In shallow or over-pressured formations, interfacial slip between formation bedding planes is possible when the effective normal stress on the bedding interfaces is low. Fracture height growth could be hindered or stopped by interfacial slip when a vertical hydraulic fracture propagates in such formations.
An interfacial slip model has been developed and implemented in a pseudo-three-dimensional (P3D) hydraulic fracture simulator. In the model, the width deformation of a fracture with interfacial slip is calculated using a displacement discontinuity (DD) method. An interface crossing criterion (Renshaw and Pollard, 1995) is used to determine if the hydraulic fracture crosses a particular bedding plane during height growth. Two interface properties of a coefficient of friction and a shear stiffness, required by the model, are defined, and the application of the Renshaw and Pollard criterion and the DD method is explained.
The direct effect of bedding plane interfacial slip is on fracture height growth and width deformation, but because of the coupling effects in hydraulic fracturing, the entire fracture geometry and fracture pressure will be affected. The simulation results based on the interfacial slip model are compared with the fracture height and pressure measured from a fracturing treatment with tracer logs, as well as with the fracture length inferred from post-fracturing production analysis. In this field case, a T-shaped fracture was considered likely to be generated based on the observed field measurements, and there is a good match in fracture height, length, and pressure between the simulation results using the interfacial slip model and the measured data.
A hydraulic fracturing simulator that includes an interfacial slip model can be used to better simulate fracturing in coalbed methane and other formations where slip between bedding planes is possible, and to improve fracture design and evaluation for such treatments.
Applying Science and Best Practices to Increase Production and Optimize Economics in a West Texas Gas Field—A Canyon Sand Case Study
Authors: Blackwood Kelly , Williamson Kaylene , Palisch Terry , Chapman Mark , Vincent Mike 
Published: October 2008

Abstract
Hydraulic fracturing is the most popular and successful stimulation treatment in the petroleum industry. Fracturing technology has opened numerous unconventional hydrocarbon frontiers that, were it not for this process, would otherwise be uneconomic to develop. However, designing the optimal hydraulic fracture is anything but an exact science. Our industry relies on many simplifying assumptions that assist in making expedient decisions, but can prevent reaching a truly optimized treatment.
Additionally, the optimal hydraulic fracture treatment rests in the eye of the beholder. Given the cyclic nature of the industry, for many companies the optimization process has become synonymous with "getting the same results at lower cost." However, to successfully optimize a fracture treatment, one should also consider design modifications which increase production, evaluating the costs and benefits of each alternative. Using economic criteria appropriate for the company goals, this process can yield an economically optimized fracture design. Unfortunately, even this method typically fails to provide an industry-wide "best practices" approach. What is deemed optimal for one company may not be optimal for another, as each company may have different financial and economic goals.
This paper will outline the approach that one Canyon Sand operator used to apply sound science and best practices to meet their financial goals by altering the hydraulic fracture design. Initial well productivity has been improved over 60% with these modifications. Since the design changes required an incremental investment, the authors will present several economic analyses of the outcome. It will also be shown that depending on a company's specific evaluation criteria (NPV, Cost Target, EUR, etc.), these design changes may or may not reach individual economic hurdles and be incorporated in future work.
Readers of this paper will see how specific design changes increased production and understand the process required to truly optimize production using economic criteria.
Miscible Interaction Between Matrix and Fracture: A Visualization and Simulation Study
Authors: Er V. , Babadagli T. 
Published: October 2008

Abstract
CO2 injection has been commonly applied in naturally fractured reservoirs (NFR) for EOR purpose. The matrix part of those types of reservoirs could be potentially a good storage medium as well. Understanding the matrix-fracture interaction during this process and the dynamics of the flow in this dual porosity system requires visual analyses. We mimicked fully miscible CO2 injection in NFRs using 2-D models with a single fracture and oil (solute) – hydrocarbon solvent pairs. The focus was on the visual pore scale analysis of miscibility interaction, breakthrough of solvent through fracture, transfer between matrix and fracture, and the dynamics of miscible displacement inside the matrix.
First, matrix-fracture interaction was intensively studied using 2D glass bead models experimentally. The model was prepared using acrylic sheets and glass beads saturated with oil as a porous media while a narrow gap of 1 mm size containing filter paper serving as a fracture. The first contact miscible solvent (pentane) was injected into the fracture and the flow distribution was monitored using an image acquisition and processing system. The produced solvent and solute were continuously analyzed for compositional study. The effects of several parameters such as flow rate, viscosity ratio (oil/solvent), and gravity were studied. Next, the process was modeled numerically using a commercial compositional simulator and the saturation distribution in the matrix was matched to experimental data. The key parameters in the matching process were effective diffusion and longitudinal and transverse dispersion coefficients. These coefficients were assigned into grid blocks in the model according to their position to the fracture.
Relative-Permeability Modifiers Used in Conjunction With Hydraulic Fracturing Can Increase Hydrocarbon Production and Reduce Water Production
Authors: Curtice R. J. , Carlson C. , Stahl M. 
Published: October 2008

Abstract
The demand for hydrocarbon production increases each year as world population continues to grow and more energy is consumed. This increasing demand has caused the oil and gas industry not only to develop new technology but also to develop reservoirs that were previously overlooked. These marginal reservoirs were deemed uneconomic, primarily because they typically existed on the outer fringes of known reservoirs or the potential productive formations were subject to excessive water production.
Many of these previously-overlooked reservoirs need to be hydraulically stimulated to make them economic. When using fracture stimulation to complete a wellbore in marginal reservoirs, it is not uncommon to produce excessive amounts of water. This excessive water production can come from the producing formation, water-wet formations which bound the producing interval, or lack of sufficient barriers between the productive zone and nearby water-bearing zones.
Because wells drilled in these marginal reservoirs are economically borderline, any additional water production resulting from the completion of these wells jeopardizes the already questionable economics. Consequently, the operators run a much higher economic risk when completing wells in these marginal reservoirs.
This paper describes a case history using a relative permeability modifier (RPM) incorporated into a hydraulic fracture stimulation treatment to reduce excessive water production. By implementing this process, it gives the operator an additional tool to increase the chances of producing formations containing hydrocarbons which had been previously overlooked. Therefore, this process can help reduce the higher economic risk of completing marginal reservoirs. Incorporating this technique into a fracture stimulation treatment resulted in the best producing well in the study area.
Experimental Analysis of CO2-Sequestration Efficiency During Oil Recovery in Naturally Fractured Reservoirs
Authors: Trivedi J. J. , Babadagli T. 
Published: October 2008

Abstract
With urgent need of greenhouse gas sequestration and booming oil prices, underground oil/gas reservoirs seems the only value added choice. A great portion of current CO2 injection projects in the world is in naturally fractured reservoir. The matrix part of these reservoirs constitutes the major oil storage unit and this oil is targeted during CO2 injection. It is our intention to show that this media could also be used as permanent CO2 storage unit while recovering oil in it. These reservoirs, however, are complex in nature and the physics of the matrix-fracture interaction process during CO2 injection is still not known to great extend.
To ease the complex nature of the problems, experiments were performed on artificially fractured (single) Berea sandstone cores saturated with n-decane. CO2 was injected at constant rates into the fracture while maintaining the high pressure into the core and the system. Injection and production data were monitored and collected using continuous data logging system. After continuous injection diffusion of CO2 was allowed to occur by shutting down the system for a specific period of time and then following a blowdown period to produce oil recovered by diffusion from matrix to fracture. At different pressure steps, produced liquid was analyzed using gas chromatography while the produced gas measured using continuous flow meter. The CO2 storage capacity of the rock with change in the pressure and the amount of oil recovered during blow down period was analyzed.
The results of the continuous injection experiments were used to obtain diffusion coefficients by matching the simulation results. Using dimensionless analysis and matrix-fracture diffusion groups, a critical number for optimal recovery/sequestration was obtained. The pressure decay behavior during the shutdown was analyzed in conjunction with the gas chromatograph analysis of produced oil sample collected during blowdown after the quasi-equilibrium reached during pressure decay. This led to insights into the governing mechanism of extraction/condensation and miscibility for recovering lighter to heavier hydrocarbons during pressure depletion from fractured reservoirs.
Performance Gains Realized With PDC Bits in Air/Foam Applications in the Appalachian Basin
Authors: Lays R. E. , Grayson E. 
Published: October 2008

Abstract
PDC bits have afforded drillers a means to improve penetration rates in many applications. However, previous attempts to apply PDC technology in air/foam drilling environments have proven unsuccessful primarily due to excessively rapid cutter wear.
A successful test of modern PDC bit designs has been conducted in a foam drilling application of the Appalachian Basin, a widely drilled basin with well-known geological properties. The initiative included identifying applications and refining operating practices while measuring the economic viability of PDC bits in this environment. Encompassing a period of 24 months, this initiative has accumulated performance data from dozens of bit runs, with drilling cost savings and reduction/elimination of borehole deviation as its objectives.
The principle area of focus involves Ordovician period formations in eastern Ohio. Foam is the primary drilling medium with an occasional need to finish the section using light mud for well control. PDC performance has delivered an ROP increase of 300% and a 30% reduction of days-on-well. This proves the ability to reduce drilling costs with PDC bits in certain air and foam applications.
This paper details methods, results, and lessons learned from this study, and translates findings into practical techniques. Operating aspects are discussed, as well as formation characteristics and down-hole conditions. A case study is provided, including performance data and dull bit photographs.
Identifying, Bypassing, and Avoiding Gas Traps in Horizontal Wells
Authors: Kreh K. A. 
Published: October 2008

Abstract
When dealing with horizontal wells in gas reservoirs with low bottomhole pressure, it is important to avoid traps –– that is, S-shaped portions of the wellbore. These wellbore traps look and act similarly to the traps under a sink or toilet, which hold water in the dip to prevent low-pressure, odorous gases in the sewer from rising into a house.
When analyzing survey data from a horizontal well, it is sometimes difficult to identify traps just by looking at the numbers. There are a few different techniques that can be employed to solve this problem. One technique is to import the survey data into a spreadsheet and solve for the slope of the well. Once the slope is found, the traps can be determined from multiple changes of slope orientation in row. Another, more visually friendly method of identifying traps is the use of 3-D graphs. By importing the survey data into a 3-D graph, the traps can easily be identified by the "S" shaped curves in the wellbore.
Once located, traps can be bypassed; depending on the length and severity of the trap, a line can be run through the trap to provide an exit for the trapped gas. Periodic treatments of N2 can be used to blow trapped water out of traps, allowing gas to migrate to surface.
This paper will discuss the concept of traps in horizontal gas wells and different methods of identifying traps, including spreadsheets and 3-D graphs. The paper will conclude with useful means of bypassing existing traps and preventing traps in future horizontal drilling.
PRISE: Petroleum Resource Investigation Summary and Evaluation
Authors: Old S. , Holditch S. A. , Ayers W. B. , McVay D. A. 
Published: October 2008

AbstractAs conventional gas resources are depleted, unconventional gas (UG) resources (gas from tight sands, coal beds, and shale) are becoming increasingly important to U.S. and world energy supply. The volume of UG resources is generally unknown in most basins outside North America. However, in 25 mature North American basins, UG resources have been produced for decades, and resources and reserves are well characterized. The objective of this work was to evaluate recoverable UG resources and determine the quantitative relations between known conventional and unconventional hydrocarbon resources in mature North American basins, with the goal of using these relations to estimate unconventional hydrocarbon resources in basin outside North America, which we call frontier basins.We used data from the U.S. Geological Survey, Potential Gas Committee, Energy Information Administration, National Petroleum Council, and Gas Technology Institute to evaluate relations among hydrocarbon resource types in the Appalachian, Black Warrior, Greater Green River, Illinois, San Juan, Uinta-Piceance, and Wind River basins. We chose these seven basins for preliminary analysis of relations between conventional and unconventional gas resources because they are mature basins for both conventional and unconventional oil and gas production. To conduct this analysis, we wrote a computer program that we call PRISE (Petroleum Resources Investigation Summary and Evaluation). Input data for PRISE, obtained from the published data sources, were the values of technically recoverable resources, which were the sum of the following resource categories: cumulative production, proved reserves, growth, and undiscovered recoverable resources. We then compared technically recoverable conventional and unconventional resources for each basin to evaluate relationship between conventional and unconventional resource volumes in these seven basins.For the seven basins studied, we found that 10% of the total recoverable hydrocarbon resources are conventional oil and gas, whereas 90% of the recoverable hydrocarbons are unconventional resources. We propose that the results of this study may be used to estimate recoverable resources from unconventional gas reservoirs in target (frontier) basins, where conventional oil and gas resources are known but unconventional resources have not been evaluated.
Application of the Bergman-Sutton Method for Determining Blend Viscosity
Authors: Sutton R. P. , Bergman D. F. 
Published: October 2008

Abstract
As the petroleum industry accesses more low gravity oil resources, modification of viscosity by blending lighter hydrocarbons has become a necessity in order to attain bulk properties that will flow though a pipeline. In the more conventional oil reservoirs, the need to estimate the viscosity of oil blends occurs when reservoir fluids are contaminated with oil base muds or when production streams from different reservoirs or fields are commingled in a single pipeline. Several methods have appeared in the literature for estimating blend viscosity. All of these methods require a measured viscosity for each component of the blend. The number of viscosity measurements is compounded when the viscosity of the blended mixture is required at several temperatures. The Bergman and Sutton method has the widest range of temperature and oil API gravity of the viscosity correlations published and has been consistently demonstrated to provide accurate results over these conditions. This method requires the component specific gravity, characterization factor (Watson K) and temperature to estimate viscosity. By using the proper mixing rules, an estimate of blend viscosity can be made with comparable or improved accuracy over the "best" published methods without the need for individual component viscosity measurements. A database of 2000 blend viscosity measurements from over 800 mixtures was created to compare the accuracy of the various methods. Viscosity measurements of the individual components in the blends studied exceeded 7600 datapoints. A diverse group of mixtures ranging from light alkane or aromatic pure components to bitumen, diesel, biodiesel, condensate, crude and assay fractions were included in this database. Blends were comprised of the typical binary mixtures but ranged up to a maximum of eight components in the mixture.
Interference Testing Using Finite-Conductivity Horizontal Wells of Unequal Lengths
Authors: Awotunde A. A. , Al-Hashim H. S. , Al-Khamis M. N. , Al-Yousef H. Y. 
Published: October 2008

Abstract
This paper presents a model for interference testing utilizing two horizontal wells of unequal lengths. The model presented is a semi-analytical model solution for interference testing utilizing two finite-conductivity horizontal wells having unequal lengths.
This model extends the previous interference testing model between two equal-length horizontal wells to a more general case in which the two horizontal interfering wells are of unequal lengths.
Sensitivity studies are performed to show the effect of horizontal well length on (1) Flux distribution in the active and observation wells, and (2) Pressure response in the active and observation wells.