bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Engineered-Particle Drilling Fluid To Overcome Coal Drilling Challenges
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 128712, ’Utilizing an Engineered Particle Drilling Fluid To Overcome Coal Drilling Challenges,’ by Sabine Zeilinger, SPE, and Fred Dupriest, SPE, ExxonMobil Development Company; Ryan Turton, SPE, Esso Australia Pty. Ltd.; and Hayden Butler, SPE, and Hong Wang, SPE, Halliburton, originally prepared for the 2010 SPE Drilling Conference and Exhibition, New Orleans, 2-4 February. The paper has not been peer reviewed.
Borehole instability and stuck pipe while drilling coal can lead to significant nonproductive time. The full-length paper describes a drilling fluid developed to stabilize coals in a program that previously was unable to achieve all extended-reach objectives. The fluid-design principles are believed to apply broadly in stabilizing coals, fractured shale, and other cleated formations.
Coal Cleats
One of the main characteristics of coal is a system of cleats, regular gaps and fractures in the coal that vary with coal maturity (Fig. 1). The fractures occur most commonly perpendicular to each other, and typically perpendicular to the bedding plane. Modeling suggests that under pressure, coal cleats may be 3 to 40 µm wide. These cleats form an interconnected network of fractures that contributes to methane production. In the case of coalbed methane, some methane adsorbed on the surfaces of the cleats may contribute to the total methane production. Drilling-fluid invasion while drilling can lead to significant formation and production damage. Concepts that have been developed for stabilization of uniform, low-permeability shales may not yield the expected results because of the unique physical characteristics of coals, particularly the existence of a cleat system.
Borehole-Instability Mechanisms
When a hole is drilled, the borehole wall must carry the load that previously was supported by the removed rock. This causes the hole to attempt to contract in the radial direction, leading to a stress concentration in the immediate vicinity of the wellbore: the tangential, or hoop, stress. If the resulting effective stress in the near-wellbore region exceeds the strength of the rock, the formation fails. Drilling-fluid pressure resists the effective stress, which limits the strain and stress that can develop in the tangential direction. Fluid density has to be increased to a level that reduces the effective stress to less than the strength of the rock. A sufficiently high mud weight can alleviate the stress concentration around the wellbore and provide sufficient support on the wall. The basic failure concept is no different in coals than in shales and other formations.
Technology Focus: Horizontal and Complex-Trajectory Wells (November 2010)
Authors: Ruszka Jon 
Published: February 2015

Technology Focus
In the late 1980s, I helped plan one of the first horizontal wells in the UK North Sea. One aspect I recall was trying to force well-planning software to form a sensible trajectory from the surface location to the geometrically defined horizontal targets. The software did not cooperate until we realized that we had to plan the well from the bottom up. We had to enter the toe and heel target locations first and then build the trajectory back to surface. I never had to do that before, but it worked.
When asked to write this introduction, the significance of that experience became apparent. It was the first time I remember planning a well from the bottom up. As horizontal-drilling activity increased, so did focus on the reservoir to improve the payback from these “more expensive” wells. As confidence to deliver these wells grew and performance improved, consideration was given to more-complex trajectories to enhance reservoir performance further. Over the last 20 years, this focus on the reservoir has driven tremendous advances in drilling and completion technology.
Initially, these technologies were applied in high-cost drilling locations, but now are relied upon to improve or even to enable productivity more widely. For example, in the Middle East, complex multilateral wells are commonly drilled by use of advanced technologies to improve reservoir performance. Another example is onshore North America. Since mid-2009, there are more rigs drilling horizontal wells in this area than any other type of well. Application of advanced technologies onshore North America has enabled production from otherwise stranded reserves in these unconventional reservoirs.
It is difficult to imagine any capability over the last 20 years that has contributed more to sustaining affordable energy supply than widespread application of horizontal wells, and we should expect the level of complexity to grow as the energy supply tightens.
Horizontal and Complex-Trajectory Wells additional reading available at OnePetro: www.onepetro.org
IPTC 13066 • “Characterizing the Flow Units in Carbonates With Production Logging and Borehole Images: Developing a Workflow in Western Offshore India,” by Ram Avtar, ONGC India, et al.
IPTC 13453 • “Utilizing Advanced Well-Placement Process To Develop Structurally Complex Areas in Maydan Mahzam Field (Offshore Qatar)” by A. Al-Ahmed, Qatar Petroleum, et al.
SPE 132816 • “An Innovative, Low-Cost Approach to Deriving Stress Conditions To Maximize Reserves Recovery in Unconventional Reservoirs” by Jason Kneedy, Chesapeake Operating, et al.
Advances in PDC Cutter Bits Improve Drilling in Hard, Abrasive Formations
Authors: Gonzales Albert , Clark Terrell , Douglas Charles , Elsik Gary , Mueller Levi , Yu Jiaqing , Shi Jibin , Zhang Youhe 
Published: February 2015

Technology Update
About 70% of the footage drilled worldwide is performed with polycrystalline diamond compact (PDC) bits. This percentage is projected to increase with the continued pursuit of hydrocarbons and geothermal energy in more challenging environments.
In these more demanding applications, conventional PDC cutting elements have often failed because of formation abrasiveness, impact damage, and thermal fatigue. To improve PDC bit drilling, a tougher, more abrasion-resistant cutter technology is required.
An extensive research and manufacturing effort was launched to develop new technology that would enable a cutter to withstand harder, more abrasive formations. Attention focused on manufacturing processes involving diamond sintering and advanced materials development. The initiative resulted in the development of the Onyx II premium PDC cutter, which has significantly improved abrasion resistance and thermal stability. The cutter has been run in the Travis Peak and Cotton Valley formations in east Texas for Devon Energy since 2010 and has generated improved rate of penetration (ROP) results while significantly reducing cost.
The new cutter represents an evolution of technology, having been introduced two years after the debut of the first generation of the high-performance shearing element. Development of the first-generation cutter was enabled by the use of a proprietary, two-step high-pressure/high-temperature (HP/HT) manufacturing method that allowed PDC bits to drill more footage at higher ROP. With bits fitted with these cutters, intervals that normally required multiple PDC bits to reach total depth could be drilled in a single run in some cases.
Engineering a New Cutter
To advance the technology to the next level, a key objective was to develop a tightly packed, high-density diamond structure that would enable the cutter to achieve better wear resistance and improved thermal stability. Experiments with several diamond grit combinations were made. The mixture of base diamond material with different size distributions was evaluated to achieve the best theoretical packing density. The mixture was then sintered using an extreme HP/HT process. The process produced additional diamond/diamond bridging and networking, compared with the existing cutter manufacturing process. Tests have confirmed that the extreme HP/HT process produces a cutter with improved thermal wear resistance capable of retaining a sharp cutting edge for a longer period than previous cutters.
Screening Method To Select Horizontal-Well Refracturing Candidates in Shale-Gas Reservoirs
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 144032, ’A Novel Screening Method for Selection of Horizontal- Refracturing Candidates in Shale-Gas Reservoirs,’ by Shekhar Sinha, SPE, and Hariharan Ramakrishnan, SPE, Schlumberger, prepared for the 2011 SPE North American Unconventional Gas Conference and Exhibition, The Woodlands, Texas, 14-16 June. The paper has not been peer reviewed.
A method was developed to screen potential horizontal-well-refracturing candidates rapidly by use of production performance and completion-data analysis. Integration of initial hydraulic-fracture-completion details augments the process and helps screen understimulated wells in different production classes. To accomplish this screening, an index called a “completion index” was defined after analysis of the completion parameters, production behavior, and their interrelationship.
Introduction
Restimulation of existing wells represents a vast unexploited resource in tight formations. In 1996, the Gas Research Institute, now the Gas Technology Institute (GTI), investigated the potential for natural-gas-production enhancement by use of restimulation in the USA (onshore, lower 48 states). The report indicated that the potential was substantial (more than 1 Tcf of reserves in 5 years), particularly in the tight gas sands of the Rocky Mountain, midcontinent, and south Texas regions. The study also stated that 85% of the restimulation potential for a field exists in 15% of the wells. Hence, the key to any successful restimulation program is being able to identify that 15 to 20% of the total well population that represents high potential for restimulation success. However, it also was determined that industry’s current experience with restimulation is mixed, and that considerable effort is required in candidate selection, problem diagnosis, and treatment design/implementation for a program to be successful.
The GTI study investigated three main classes of candidate-selection methods: production-performance comparisons, pattern-recognition-technology/virtual-intelligence methods, and production-type-curve matching. The study concluded that although virtual-intelligence methods were relatively better compared to production type curves, no universal method exists that enables selecting restimulation candidates across different geologic settings. Use of production statistics alone was the least-effective process.
Innovation: The Use of Seismic - A Game Changer in Defining Prospects
Authors: Imomoh Egbert 
Published: February 2015

President's column
Early in my career, my colleagues in the exploration department had especially large tables, upon which they spread large seismic sections with many wiggles (which seemed to make sense to them but not me) so that they could identify potential exploration targets. This has changed over time, especially with the advent of 3D seismic.
In this month’s column, I wish to focus on the innovative ways that have emerged in exploration. That is where our journey starts, as we would not have a thriving oil and gas industry without the geoscientists who continuously find hydrocarbon accumulations that can be developed, produced, and brought to the market. The advent of huge computing capability and the availability of high-capacity telecommunications facilities make the early exploration processes sound as if they were of the Stone Age, particularly to today’s young geoscientist sitting behind large desktop screens viewing and manipulating data. I give the example of the application of 2D, 3D, and 4D seismic coupled with new acquisition and processing techniques to illustrate what innovation can do and has contributed to our industry.
Prior to the advent of seismic data, the search for hydrocarbons was based on observation of surface phenomena (outcrops, seeps, etc.). The use of seismic waves to define the subsurface emerged in the early 1900s following observation of waves that were created by earthquakes. Some innovative scientists saw the potential of how surface-induced waves could be used to better define the geology of the Earth and, through the data obtained, provide a better picture of the subsurface structure and the potential for hydrocarbon accumulation.
The first well to find oil through the use of seismic was drilled in Brazoria County, Texas, in 1924. Subsequently, thousands of prospects all over the world were identified and drilled based on this technology, which was innovative when first used (Seismic, 1999). The early explorationists were trained to “eyeball” potential accumulations by using their experience to evaluate seismic sections that were displayed as a 2D plane to generate maps that were used to drill exploration wells.
Stress Management Could Change Tune for Shale Completions
Authors: Rassenfoss Stephen 
Published: February 2015

Shale fracture
Fracturing a well in more places using tightly spaced clusters can prove to be counterproductive. The downside, according to recent work by Mukul Sharma, a professor at The University of Texas at Austin, and others, is that the hydraulic force that breaks up the rock is also capable of creating a zone near the well where the path of least resistance for fracture growth runs parallel to the wellbore.
When fractures are closely spaced there is more of a chance that the pressure of fracturing could lead to fractures that are shorter, curved in the direction of the previous fracture, and, in extreme cases, each might run into the other.
Sharma’s work comes at a time when the industry has been doing more fractures spaced closer together in hopes of opening up greater volumes of rock in hard-to-produce unconventional formations, and the results raise tough questions.
The study of stress effects is part of a wider effort by the industry to gain an understanding of why so many fractures fail to perform.
The issue is that adding more stages for fracturing does not always result in significant additional output. And tight spacing between fractures is becoming more common as more wells are clustered on pads and fractured at the same time.
Shifts in the stress pattern caused by fracturing have been reported by others, but Sharma is taking it further, with a field test of a completion method that changes the normal order of fracturing. “People sort of knew this would happen,” Sharma said. “But people didn’t fully appreciate how big an effect it would have operationally.”
This is one of the projects under way within Sharma’s hydraulic fracturing and sand control joint industry group, which is made up of 25 operators and service companies. It has moved from simulations predicting stress reorientation to planning the field trial of the completion technique designed to maximize the distance from one hydraulic fracture to the next. The thinking is that wider spacing will leave a space in between for greater fracture growth by the third fracture, resulting in more production and increased ultimate recoveries.
Novel Nanoparticle-Based Drilling Fluid Reveals Improved Characteristics
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 156992, ’Novel Nanoparticle-Based Drilling Fluid With Improved Characteristics,’ by Mohammad F. Zakaria, Maen Husein, and Geir Hareland, SPE, University of Calgary, prepared for the 2012 SPE International Oilfield Nanotechnology Conference and Exhibition, Noordwijk, The Netherlands, 12-14 June. The paper has not been peer reviewed.
A new class of nanoparticle lost-circulation material (LCM) has been developed. Two different approaches of nanoparticle formation and addition to oil-based drilling fluid have been tested. All nanoparticles were prepared in house, either within the oil-based drilling fluid (in situ) or within an aqueous phase (ex situ), with the latter being eventually blended with the drilling fluid. Under a low-pressure/low-temperature (LP/LT) American Petroleum Institute standard test, more than 70% reduction in fluid loss was achieved in the presence of nanoparticles, compared with only 9% reduction in the presence of typical LCMs.
Introduction
LCMs with diameters in the range of 0.1–100m may play an important role when the cause of fluid loss occurs in 0.1-Μm to 1-mm porous formation. In practice, however, the size of pore openings in shales that may cause fluid loss varies in the range of 10 nm–0.1 m, where nanoparticles as LCM could fulfill the specific requirements by virtue of their size domain, hydrodynamic properties, and interaction potential with the formation. Nanoparticles are defined as particulate dispersions or solid particles with a size in the range of 1–100 nm. These particles are smaller than microparticles, have a high surface/volume ratio, and may provide superior fluid properties at low concentrations of the additives. The main application of nanoparticles would be to control the spurt and fluid loss into the formation and, hence, control formation damage. The presence of nanoparticles can lead to better sealing at an earlier stage of filter-cake formation and, subsequently, a thinner impermeable mudcake. Because of their high surface/volume ratio, the particles in the mudcake matrix can be removed easily by traditional cleaning systems during completion. Thus, the nanoparticles can be used as rheology modifiers, fluid-loss additives, and shale inhibitors at low concentrations without the fear of particles lingering in the drilled well.
Shale-Gas Reserves Estimation: Multiple Decline-Curve-Analysis Models
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 161092, ’A New Approach to Reserves Estimation in Shale-Gas Reservoirs Using Multiple Decline-Curve-Analysis Models,’ by Srikanta Mishra, SPE, Battelle Memorial Institute, prepared for the 2012 SPE Eastern Regional Meeting, Lexington, Kentucky, 3-5 October. The paper has not been peer reviewed.
Recent interest in the Marcellus and Utica plays has renewed attention to the problem of reliably estimating recoverable reserves from low-permeability shale-gas formations. Over-optimistic results obtained from the commonly used Arps’ hyperbolic model have led to development of alternative decline-curve-analysis models that are based on empirical considerations (e.g., the Duong power-law model) or mechanistic considerations [e.g., the Valko stretched-exponential-decline model (SEDM)]. This work addressed discriminating between such models (including a new mechanistic model proposed for decline-curve analysis that is based on the Weibull growth curve) with only limited production data. A new approach to aggregating estimated-ultimate-recovery (EUR) forecasts from multiple plausible models is presented.
Introduction
The use of horizontal drilling, supplemented by multistage hydraulic fracturing, spurred the production of shale gas, including the Barnett, Eagle Ford, Haynesville, Marcellus, and Utica plays. The result is challenges in production forecasting and reserves estimation.
Projecting production-decline curves is, perhaps, the single most widely used method for forecasting production from tight gas and shale-gas wells. Future-production potential at any given time and an estimated ultimate recovery (EUR) are assessed by fitting an empirical model of the well’s production-decline trend and by projecting this trend to the well’s economic limit or a common cutoff time (e.g., 30 years). The most commonly used production-decline-curve model is Arps’ hyperbolic model. However, forcing the model to fit production data from shale-gas wells has been found to result in over-optimistic results of EUR, stemming from physically unrealistically high values of the decline exponent to force the fit. Several alternatives have been proposed for analyzing decline curves for tight gas wells. One approach involves constraining the late-time decline rate to a more-realistic value on the basis of experience or analogs. Another approach involves searching for empirical decline-curve models that impose physically meaningful parameter definitions and finite EUR values on model predictions. A key issue associated with the use of multiple models is how to discriminate between them with limited production periods, and how to combine the model results to yield an assessment of uncertainty in reserves estimates.
Comments: Reader Feedback (November 2013)
Authors: Donnelly John 
Published: February 2015

Editor's column
Every year, JPT surveys SPE members to determine whether the publication is fulfilling its readers’ needs and to get opinions about ways to make the magazine better. JPT has changed significantly over the past 2 to 3 years—it has doubled the amount of editorial content, increased coverage of new and emerging technology, and added several new features. All of these improvements were designed to help JPT contribute to SPE’s mission of providing the best quality upstream technical information to the industry, while adding to the depth and breadth of coverage to match the industry’s growth.
The survey was sent to a representative sample of members matching SPE’s geographic and age distribution. Invitations to participate in the 2013 SPE JPT Reader Survey were sent to 59,893 professional (nonstudent) members. More than a third of respondents classified themselves as engineers, with the next highest category managers at 20%. Just under half of those participating in the poll reside in North America, with 52% outside of North America, and 68% of respondents have at least 10 years of experience in the oil and gas industry.
JPT continues to be rated highly by readers—76% of respondent rated the magazine’s content “very good to excellent,” and more than 97% rated it “good to excellent.” Just under 80% said JPT was better than other publications serving the E&P industry, and a third of respondents called it “significantly better.” The magazine is also read more than other upstream publications. More than 83% of respondents said they always or frequently read JPT; the next highest score by an upstream publication was 40%. In addition, just under 90% of readers consider JPT to be useful or very useful to them in their jobs.
Readers are interested in new technology and applications of new and existing technology. Features in the magazine that are the most read include Technology Update, Technology Applications, summaries of technical papers, and staff-written feature articles on emerging technology and technology trends. The most popular technical topics include unconventional reservoirs, hydraulic fracturing, field development, completions, mature fields, well revitalization, and high-pressure/high-temperature challenges. Topics of growing interest compared with the 2012 reader survey are production/facilities, offshore facilities, seismic applications, HSE, field development, and drilling fluids.
Readers rated JPT’s biggest strength its technical content, and its main weakness the fact that not all issues cover topics relevant to the reader. Compared with last year’s survey, more readers are accessing JPT online as well as on a mobile device such as a tablet or mobile phone, but print is still by far the most preferred way to read JPT.
JPT’s 44-person Editorial Committee, which includes practicing petroleum professionals from around the globe, and SPE staff will use the information in the survey to further improve the magazine and to ensure that JPT remains useful and relevant to its readers.