bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effective Pressure and Microstructure Control on Resistivity Formation Factor and Seismic Waves Velocities
Authors: Tinni Ali , Sondergeld Carl. H. , Rai Chandra , Simo Herve 
Published: October 2011

Abstract
In clay-rich tight gas sand, conventional resistivity methods yield inconsistent saturation estimates, and simple velocity models such as the Biot-Gassmann do not accurately predict the saturation induced velocity variations in these formations. This paper presents an experimental study designed to better understand the electrical and acoustic properties of clay-rich tight gas sands. A comprehensive set of measurements including porosity - permeability, mineralogy, mercury capillary pressure and SEM imaging were conducted on six tight gas sands cores saturated with 25, 000 ppm NaCl brine. To complete the experiments, resistivity, compressional and shear wave velocities were measured on the same tight gas sands as a function of hydrostatic confining pressure (500 psi to 5000 psi) and pore pressure (500 psi to 3000 psi). During these experiments, the time necessary for pore pressure equilibrium was determined to be at least three hours. The tight gas sands studied have porosities ranging from 4.5% to 8.3% and permeabilities between 18 μd and 82 μd. Their mineralogy is dominated by the presence of quartz with clay content as high as 28 wgt%. The SEM imaging shows the presence of a significant number of low aspect ratio pores and authigenic microcracks. The formation factor and seismic velocities data were used to evaluate the effective pressure law for each of these petrophysical properties. The effective pressure dependency for the formation factor and the seismic velocities observed are in opposition to each other. The analysis of the effective pressure coefficient n for the formation factor showed a general increase from a value generally close to 1, by 31% over a differential pressure range of 500 to 2500 psi. This same coefficient n generally equals about 0.92 for low differential pressure but decreased by about 30% for compressional and shear wave velocities. Using simple considerations, we established that a change in n values by 30% can induce an error in pore pressure prediction of 15%.
Evaluating the Long Term Benefits of Improved Fracture Treatments
Authors: Blackwood K. , Flowers J. , Handren P. , Pope C. , Palisch T. , Chapman M. , Godwin J. 
Published: October 2011

Abstract
It is understood that improved hydraulic fracture treatments increase production rates from most reservoirs. However, are these gains short lived, or do they yield incremental recovery? Is the improved productivity related to recovery of additional reserves or merely an acceleration of existing reserves?
Frequently, the impacts of design improvements are demonstrated by improved initial production (IP) rates or perhaps evaluated base on 6- to 12-month cumulative production increases. Field development decisions are often made based on these initial results, never again to be reviewed for long term corroboration. Rarely are the rate, reserves, and economic impact of these design changes evaluated and documented over longer production periods. As such, while a particular design change may pay out in two or three months, the question remains as to whether the enhancement represents merely a short term acceleration of production or in fact an increase in hydrocarbon recovery.
This paper will review the production results from several tight gas and unconventional reservoirs in which hydraulic fracture designs were upgraded to premium proppant, for which the results were documented in previous SPE papers. Areas evaluated include wells in the Cotton Valley-Taylor and Haynesville Lime of East Texas, the Haynesville Shale of North Louisiana and the West Texas Canyon Sand; all were evaluated and documented shortly after implementation. Raw production differences will be reviewed along with decline curve analyses, using updated production to evaluate both near and long term recovery impacts.
In addition to (re)evaluating for technical success, economic evaluations are provided to determine whether the design improvements truly resulted in favorable economic outcomes, as suggested in the original evaluations. When possible, these new evaluations will be compared to original recovery forecasts to ascertain whether the original conclusions still hold.
This paper should be of interest to anyone who evaluates the benefits of fracture design changes in their completions, and will provide insight on the accuracy of initial evaluations compared to actual long term production. It will also further investigate the benefits of improved fracture designs.
Parametric Investigation of Shale Gas Production Considering Nano-Scale Pore Size Distribution, Formation Factor, and Non-Darcy Flow Mechanisms
Authors: Michel G. G. , Sigal R. F. , Civan F. , Devegowda D. 
Published: October 2011

Abstract
The effects of the parameters involved in shale gas reservoir simulation are investigated using an improved transport equation for description of gas flow in nano-Darcy permeability media. This approach takes into account the effects of molecular collisions at the pore wall and is valid in all flow regimes: Darcy, slip, transition, and free-molecular flow. The study generalizes a transport equation valid for all flow regimes for an ideal gas in a capillary tube and extends the formulation to quantify the effect of a distribution of pore sizes for different flow regimes. We first describe the adopted methodology to model ideal gas transport and then account for real gas behavior by modifying the conventional definition of the mean free-path. The relationship of this approach to the Klinkenberg correction for slip flow and other published formulations that are described as the sum of a Darcy term plus a diffusive transport term are examined. An application of the present approach and its implications are demonstrated by means of a numerical example involving a hydraulically-fractured shale gas reservoir producing at a constant rate. The bottomhole pressure predictions from the non-Darcy formulation indicate a substantial deviation from the bottomhole pressure predicted by assuming Darcy flow and consequently, can be expected to have serious implications for production forecasting and planning for well abandonment. In particular, for infinite acting flow regimes that are commonly observed for shale gas wells, our calculations indicate that flowing bottomhole pressures tend to be higher than those calculated using a transport formulation governed by Darcy's law, thereby describing the potential for significantly enhanced productive well life.
Fiber Optic Strain Sensing at the Sand Face Enables Real-Time Flow Monitoring and Compaction Mitigation in Openhole Applications
Authors: Earles Denise M. , Stoesz Carl W. , Surveyor Nilufer , Pearce Jeremy G. , DeJongh Hans A. 
Published: October 2011

Abstract
Subsurface stresses can cause formation faults, slippage, and reservoir compaction, which can damage or permanently shut in a well. Traditional means of detecting these failures are limited and usually require moving a costly rig onto locations, and then interrupting production to re-enter the well. This results in late detection of issues and allows limited counteractive options.
A new system has been developed to actively monitor strain and temperature of wells. The system consists of three key enabling technologies: A fiber optic support device deployed at the sand face, a cost effective high-flow liner system that protects the instrumentation in openhole applications, and two optical wet connects for up to 12 channels.
The fiber optic support device provides a means of holding a helically wrapped optic fiber rigidly in place at the sand face. This new technology can be installed over traditional sand screens in gravel pack or frac pack applications, with no negative impact on the sand control functionality of the screens, or the quality of the pack. The installed fiber optic provides the equivalent of a strain gauge positioned every centimeter along the length of the producing zone.
For openhole applications, a high-flow liner system was developed to protect the fiber optic support device, and the control lines. This system includes a special quick connect that simplifies the on-rig assembly and allows torque transmission in an openhole deployment.
The final key to this system is the two 6-channel optical wet connects, allowing a total of 12 connected channels. This game changing technology provides an information conduit between the fiber optic at the sand face and operators at the surface. The same wet connect can also be used to connect more traditional means of measurements such as pressure-temperature gauges, or distributive temperature sensing (DTS).
The information relayed through this system allows the operator to infer flow and detect subsidence or compaction of the sand face before the well is compromised, allowing time to plan and execute mitigative actions. This paper will discuss the design, testing, and potential applications of this new system.
Interpretation of CO2 Sequestration-Induced Surface Deformation over KB-502 at Krechba, Algeria
Authors: Davis Eric 
Published: October 2011

Abstract
The Krechba field is part of a gas development in Central Algeria where CO2 is being injected to develop carbon-storage techniques within an active gas-producing reservoir. In 2004, three CO2 injectors (KB-501, KB-502, and KB-503) began placing CO2 in a 15-to 20-m thick target zone at a depth of roughly 1850 m. Above the target zone lies approximately 1, 000 m of very low permeability carboniferous mudstones. This caprock is expected to provide long-term sequestration of the injected CO2.
Surface-deformation monitoring measured using differential interferometric synthetic aperture radar (InSAR) has proven to be one of the more useful of a wide array of monitoring methods deployed at Krechba. The unique, horseshoe-shaped uplift pattern around KB-502 has been the subject of several technical papers to date. The analysis presented in this work, however, is unique in that it does not place any constraints on the location of strain sources that produce the measured uplift. The results of this analysis, which indicate strain sources shallower than the injection horizon, coincide well with formation properties determined from logs and 3D seismic surveys. The implications of fluid intrusion into depths shallower than the injection interval, even if that fluid is displaced formation water rather than CO2, are significant for the project operators.
Well Performance Diagnosis with Temperature Profile Measurements
Authors: Tabatabaei M. , Tan X. , Hill A. D. , Zhu D. 
Published: October 2011

Abstract
The measurement of the temperature profile of a well has been a primary part of production logs since the inception of these logs and continues to be a routine production logging measurement. In recent years, the increasing application of fiber-optic based distributed temperature sensors, either permanently installed in the well completion, or temporarily deployed, has provided a source for additional temperature profile data. In this paper, we present methodologies for interpreting numerous conditions in wells from temperature profiles. For each method, the underlying theory of the interpretation, and one or more field examples are presented. The most fundamental well property that can often be obtained from a temperature profile is the well's inflow profile - the locations and relative rates of inflow along the well. Simple analytical methods for interpreting the flow profiles of vertical oil producing wells are presented along with examples of this interpretation.
Another key application of temperature profile measurements, particularly for horizontal wells, is the location of water or gas entries in oil-producing wells. We will show how water or gas entries create temperature anomalies along horizontal wells caused by the differences in the Joule-Thomson coefficients of the different phases or by the water or gas source being from below or above the well depth, as in a coning situation. We illustrate how such water or gas inflows can be quantitatively identified by applying standard inversion methods to the measured temperature profiles, yielding the locations and rates of water or gas entries.
Another growing application of temperature profile measurements is the analysis of stimulation treatment (fracturing or acidizing) fluid placement. Temperature profiles measured during treatment pumping, during a flowback period, or after shut-in can be analyzed to determine the amount of stimulation fluid placed in different completed intervals along the well. A related analysis method using transient temperature profile measurements provides a means of determining layer properties of permeability, skin factor, and damage depth. This method can be applied before a stimulation treatment to aid the stimulation design, or post-job to evaluate treatment results.
New Perspectives in Technology Transfer and Training for the Real World
Authors: Fiffick William , Markham Meredith A. 
Published: October 2011

Abstract
As oil field engineers, scientists, and technologists are challenged to solve new and more complex problems, the ability to properly apply oil field technology is vital to our success.
But as the technology is applied, it can be just as important to document and transfer those "lessons learned." While much of the training provided to those entering the workforce is built on foundational concepts, products, and processes, much more is required. New processes, practices, and products are constantly being invented, refined, and/or improved. The ability to quickly and systematically capture these lessons can save hundreds of work hours. Applying new technology can also pay great dividends by helping field engineers propagate technology and foster continuous improvement.
So, how do we capture that knowledge and those lessons learned? What best practices can be modeled? How do we leverage learning technology to archive, and transfer these important lessons? How do we optimize the time commitments from our subject matter experts? What emerging technologies are available which may assist with the capture, transfer, and delivery efforts? How are the varied learning methodologies satisfied?
The following is a case study from a major oil field services company outlining effective and efficient technology transfer efforts. Best practices as well as lessons learned are discussed.
Evolution of High Build-Rate RSS Changes the Approach to Unconventional Oil and Gas Drilling
Authors: Hummes O. , Janwadkar S. , Powers J. , Bond P. , Anderson M. , Chesher S. , Paugh W. , Wiggers C. , Roberts G. , Schmidt S. , Hildebrand J. 
Published: October 2011

Abstract
This paper discusses the development, testing and optimization of a rotary steerable system (RSS) developed specifically to address the challenges around drilling wells in unconventional reservoirs in North America. As with offshore areas, rotary steerable drilling technology has rapidly gained acceptance for onshore use because of its clear advantages in directional control, wellbore placement and lateral reach, while matching or exceeding the drilling performance of conventional systems. The further growth of RSS into the drilling of unconventional reservoirs has been limited by the build-rate (BUR) capabilities of established RSS that prevent operators from successfully drilling curve and lateral sections in one run. In recent years, service companies have worked to improve the capabilities of rotary steerable drilling systems to meet the specific needs of drilling horizontal wells in unconventional oil and gas reservoirs. Due to lease spacing and limited vertical depths to achieve horizontal orientation, greater buildup rates (BUR) are required to maximize the lateral lengths in the reservoir. In addition to developing higher doglegs in the curve, the system should also enable lateral control to minimize tortuosity, facilitate easy casing running and optimize successful multistage fracturing. The authors outline how specific challenges, such as reduction in drilling time, improved wellbore placement, and more efficient completion and fracturing operations are addressed by the introduction of the new system. Included in this paper is a description of how the bottomhole assembly (BHA) and drill-bit properties are matched and optimized to deliver best directional control and drilling performance, according to formation characteristics in the Granite Wash play in the central USA. Explanations detail how the new system capabilities expand the possibilities to develop reservoirs using pad drilling, the use of more complex well profiles and real-time reservoir navigation, leading to increased hydrocarbon production.
Improved Petrophysical Core Measurements on Tight Shale Reservoirs Using Retort and Crushed Samples
Authors: Handwerger D. A. , Suarez-Rivera R. , Vaughn K. I. , Keller J. F. 
Published: October 2011

Abstract
Gas shales have become an important resource for the production of hydrocarbons in North America, and are being explored as a resource on other continents as well, based on their rapidly increased importance to the North American market and promise to boost domestic production elsewhere. There are numerous pricing and geopolitical reasons for this active exploration, but regardless of where in the world they are being explored, gas shales share some fundamental properties that make them virtually impossible to analyze with conventional core analysis methods or conventional petrophysical models based on log data. These properties are basically that gas shales are tight, with permeabilities in the 10s to 100s of nD, have low (effective) porosity, typically less than 10%, and have high kerogen and clay content. While there are some variations of these themes (e.g. shales with higher detrital input, making them siltier or silty-laminated), in general the tightness of the rock and abundance of clay minerals and kerogen pervades, and that causes a number of challenges to analysis.
We have developed analytical methods for evaluating these reservoirs on core by using crushed material to enable better access to the pore space, retort analysis to measure separately free, bound and structural water saturations and also distinguish water from oil, and pressure transient analyses for the determination of permeability. Conventional core analyses (e.g. Dean Stark), applied to kerogen- and clay-rich rocks fails in separating free from bound waters and water from light oils, thereby missing critical inputs into calculating effective saturations, effective porosities and clay-bound water volume. In addition, the amount of oil recovered from retort, as an independent quantity, can be a useful proxy for kerogen maturity. From a permeability standpoint, unconventional reservoirs are usually too tight to allow for steady-state permeability measurements, and microfracturing is often too pervasive to allow for reliable permeability measurements on whole plug samples. As a result, we have developed a crushed-sample pressure decay system to measure the nD permeabilities typical of shales, and a stepped confinement pulse-decay method for measuring micro-Darcy (and higher) permeabilities in more texturally complex, siltier or sandier unconventional reservoirs that typically have these higher permeabilities.
Modeling of Pressure and Solution Gas for Chemical Floods
Authors: Roshanfekr M. , Johns R. T. , Delshad M. , Pope G. A. 
Published: October 2011

Abstract
The goal of surfactant-polymer flooding (SP) is to reduce interfacial tension (IFT) between oil and water so that residual oil is mobilized and high recovery is achieved. The optimum salinity and solubilization ratio that correspond to ultra-low IFT have recently been shown to be a strong function of the methane mole fraction in the oil at reservoir pressure in some cases. We incorporate a recently developed methodology to determine the optimum salinity and solubilization ratios at reservoir pressure into a chemical flooding simulator (UTCHEM). The proposed method determines the optimum conditions based on density estimates using a cubic equation-of-state and measured phase behavior data at atmospheric pressure. The microemulsion phase behavior (Winsor I, II, and III) are adjusted based on these predicted optimum salinity and solubilization ratio in the simulator. Parameters for surfactant phase behavior equation are modified to account for these changes and the trend in equivalent alkane carbon number is automatically adjusted for pressure and methane content in each simulation gridblock. We use phase behavior data from several potential SP floods to demonstrate the new implementation. The implementation of the new phase behavior model into a chemical flooding simulator can greatly aid in the design of SP floods so that SP flooding failures are less likely to occur. The simulator will also make more accurate estimations of oil recovery. The new approach could also be used to handle free gas that may form in the reservoir. We show that not accounting for the phase behavior changes that occur when methane is present at reservoir pressure can greatly affect the oil recovery of SP floods. Improper design of a SP flood can lead to more oil being produced as a microemulsion phase than as an oil bank. This paper describes the procedure to implement the effect of pressure and solution gas on microemulsion phase behavior in a chemical flooding simulator, which requires the phase behavior data measured at atmospheric pressure.
Eliminating Slickwater Compromises for Improved Shale Stimulation
Authors: Brannon Harold D. , Bell Charles E. 
Published: October 2011

Abstract
Hydraulic fracturing stimulation is generally accepted as requisite to obtain commercial production from low permeability formations, including oil- and gas-bearing shales. Low viscosity slickwater fluids generate fractures of lesser width and therefore greater fracture length, theoretically increasing the complexity of the created fracture network for better reservoir-to-wellbore connectivity. Unfortunately, slickwater fluid is an inherently poor proppant carrier, necessitating high pump rates to achieve flow velocities sufficient to overcome the tendency of the proppants to settle. Proppant settling within surface equipment or long horizontal laterals can result in premature treatment termination and poor productivity. Crosslinked and linear gel systems have been used to mitigate the proppant settling and placement concerns, but the high viscosity that accomplishes this objective may significantly reduce the desired fracture complexity.
A ‘new’ crosslinked polymer system deploys the best attributes of slickwater and conventional crosslinked fluids systems to maximize proppant transport through the surface equipment and long laterals before breaking to create a desirably complex fracture network. The fluid is crosslinked on surface with an ultra-low loading of high-yield guar polymer loading that achieves surface viscosity sufficient to carry proppant from the pumping equipment through the horizontal lateral and perforations. Controllable viscosity degradation converts the fluid to a slickwater viscosity within the reservoir to provide the desired complex fracture network. Gel break-back timing may be used to control the onset of complex network development. For example, it may be desirable to generate a planar fracture for a distance from the wellbore before reverting to the low viscosity-induced complex fracture development. Thus, the system displays the positive attributes of both slickwater and crosslinked gel systems while simultaneously overcoming the negatives associated with each.
Fracture modeling illustrates the utility of the fluid performance management and controlling the onset of complex network development. Case histories compare applications of the system to offsets treated with conventional slickwater and crosslinked gel fluids, including well performance and an assessment of the impact upon operational reliability.