bluuebunny/crossref_metadata_2025 huggingface dataset:
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.
Techbits: Education Forum: It Is More About Head Content Than Head Count
Authors: JPT staff _
Published: February 2015

Techbits

SPE recently sponsored a forum on the need to ensure an appropriately educated upstream engineering workforce in 2020 and beyond. Titled 2020 Foresight: Ensuring Excellence in Petroleum Engineering Education, the session took place in August in Idaho. Attendees concluded that the current petroleum engineering educational systems are not sustainable to produce the talent that the oil and gas industry will need in 2020 unless the industry and academia make this issue a priority and collaborate on ways to resolve the anticipated underlying gaps.

The idea for the forum grew out of a series of colloquia on petroleum engineering education dating back to 1991. Past colloquia were geared toward aligning education with meeting the industry’s needs, as well as developing continuous improvement processes and refining program assessment methods. Over time, the SPE Board of Directors has become concerned about potentially significant problems developing in the global petroleum engineering education system and the ability of the system to sustainably produce the talent that industry will need in the next decade. The SPE Board sanctioned the forum in an effort to bring academia and industry representatives together to collaborate and propose solutions to the issues.

Forty-seven participants from 10 countries on five continents representing academia (57%) and industry (43%) spent a week analyzing the current and future engineering resourcing environments. The group identified the following key issues to help define the business imperative toward making petroleum engineering education more sustainable.

Although regional pressures exist near term in sub-Saharan Africa, the United States, and the Middle East/North Africa region, there may be a talent gap rather than a people shortage in the industry by 2020. Gaps in both technical and nontechnical skills were identified as barriers for an effective petroleum engineer in the future. This may make a degree in petroleum engineering with relevant course work even more valuable to some companies, where new petroleum engineering hires can contribute earlier than graduates from other engineering disciplines without the domain-specific training.

Petroleum engineering faculty demographics are of significant concern and the feeder pool of PhDs being attracted to academia is currently inadequate. The number of current faculty vacancies was cited as a leading indicator. For example, nearly two-thirds of the US faculty will qualify for retirement in the next 10 years. Although demographic data was only available for US petroleum engineering departments, faculty from other regions attending the forum anecdotally agreed that the situations in their countries or regions were similar or more challenging.

A root cause of the faculty shortage is that petroleum engineering PhD faculty compensation and benefit packages are not competitive with industry packages.
Cracking the Cline: A New Shale Play Develops in the Permian Basin
Authors: Jacobs Trent
Published: February 2015

Cline Shale

Early in its development, the Cline shale was hyped as the next Eagle Ford or Bakken with more oil and gas than they have combined.

The lofty projections of the Cline shale’s potential, located in west Texas on the eastern side of the Permian Basin, were extrapolated from information presented by Devon Energy to financial analysts in April 2012.

At that time, the company’s data regarding the emerging play suggested the possibility that as much as 3.6 billion BOE lie trapped within Devon’s 500,000 acres of Cline shale. Analysts looking for North America’s next major unconventional resource then calculated that the entire formation, roughly 140 miles long and 70 miles wide, held between 30 and 35 billion BOE, which would make it one of the largest discoveries in the world.

That hasty estimate did not take into account how much of the potentially mammoth resource could be economically recoverable. Devon said it is not far enough along in its Cline shale operations to share information.

Other operators in the Cline have encountered issues that make producing from the formation a challenge, such as heavy-clay content, and as a result, the production quality is not consistent across the play.

“There was a lot of optimism up front,” said Benjamin Shattuck, an upstream analyst at Wood Mackenzie in Houston. He said that the variability in initial production rates among the handful of operators drilling horizontal wells in the Cline has revealed the best acreage to be in the west Texas counties of Glasscock and along the western side of Sterling. “That doesn’t mean that there have not been decent results outside of that area,” Shattuck said, “but I think some of the excitement has been tempered a little bit.”

Tempered perhaps, but not all the way gone. The operators with early success in the Cline and even those facing setbacks are moving forward on their investments in drilling the shale and building up the infrastructure needed to support field development for years to come (Table 1). What remains to be determined is whether the Cline will be a uniform and commercially competitive formation across the vast area that it encompasses, or be limited to small pockets in which the shale is conducive to production.

Three-Finger Black Shale

Before it came to be known as the Cline, the nickname for the formation was the “Three-Finger Black Shale” because of its rich darkness seen in core samples, and the distinctive resistivity peaks identifying its location during vertical well logging (Fig. 1). Operators have drilled more than 1,500 vertical wells through the formation in the past several years. The vertical drilling programs provided oil companies with the geological and petrophysical data that they are using today to understand and successfully deplete the formation of hydrocarbons by drilling into it horizontally.
Challenges and Solutions Surface at SPE Annual Conference
Authors: JPT staff _
Published: February 2015

Conference review

The frontiers of deepwater and pre-salt reservoirs garnered much attention at the 2013 SPE Annual Technical Conference and Exhibition (ATCE) held in New Orleans in October. The conference brought together 12,028 oil and gas professionals from around the world.

“This year’s ATCE ranked as the highest attended since 1999,” said Egbert Imomoh, 2013 SPE President. “The event capped a year of tremendous success for SPE with a growing global membership, increased technical content, and strong financial performance.”

The conference received 1,773 technical paper proposals this year, compared with slightly less than 1,500 a year ago. The 2013 program of 52 sessions included more than 300 technical papers and 67 ePoster presentations. With panel sessions, there were more than 400 presentations in total.

Opening Session

Discussion at the opening general session revolved around safety, technology, and the cost of deepwater oil and gas projects. A government official and four industry top executives made up the panel for the session titled “Deepwater Exploration and Development—Challenging the Limits.”

Lars Herbst, Gulf of Mexico (GOM) regional director for the United States Bureau of Safety and Environmental Enforcement (BSEE), described GOM deepwater drilling rig activity as very robust, having recovered from the post-Macondo drilling moratorium. Seventeen new deepwater rigs are expected to enter the GOM under long-term contracts by the first quarter of 2015.

“So, to begin, we are talking about opportunity for drilling. There is plenty of opportunity,” he said.

In GOM deepwater development, 10 projects have been sanctioned and 10 discoveries are in various stages of appraisal, Herbst said. The deepwater activity is “going to require not only new technology but increasingly qualified employees,” Herbst said. “We often talk about competency, but it is going to be capacity as well.”

The BSEE official discussed deepwater challenges and risks. “There is a difference,” Herbst said. “A risk is something that has the capability of causing harm or injury, and a challenge is something that hopefully motivates us to move the status quo.” An item can move from one category to the other, he noted.

The challenges Herbst cited are high-pressure/high-temperature technology, improving blowout preventers (BOPs), enhanced oil recovery, and dual-gradient drilling, as well as workforce issues.

For risks, Herbst noted recent failures in small components, such as shackles and bolts. While no large incident occurred, “a small component can cause a major failure,” he said. There have also been numerous dynamic positioning failures in the past several years. In well control since Macondo, there have been shallow-water incidents and some of them “translate to deep water,” he said.

John Gremp, chairman and chief executive officer of FMC Technologies, put the industry’s deepwater needs in perspective.
Nanoemulsion-Enhanced Treatment of Oil-Contaminated Cuttings
Authors: Denney Dennis
Published: February 2015

This article, written by Dennis Denney, contains highlights of paper SPE 162401, ’Nanoemulsion-Enhanced Treatment of Oil-Contaminated Oil-Based Drill Solids,’ by Wasan Saphanuchart, SPE, Yoong Shang Loke, SPE, and Chun Hwa See, SPE, BCI Chemical Corporation, prepared for the 2012 Abu Dhabi International Petroleum Exhibition & Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed.

When oil-based mud is used, the drilled formation solids (cuttings) are regarded as controlled or hazardous waste. As such, they can be disposed of in three ways: decontamination treatment followed by discharge into the sea, injection of the cuttings into the well, or transfer to a controlled hazardous-waste landfill. The lowest environmental effect for solids disposal, especially for offshore operation, is decontamination treatment followed by discharge. However, conventional decontamination technology exhibits limited efficiency in extracting oil from the drill solids.

Introduction

One function of drilling mud is a washing action to remove cuttings from the wellbore. The mud returns to the surface with entrained cuttings and, typically, flows through shale shakers, desanders, desilters, hydrocyclones, centrifuges, or other devices to separate the cuttings from the mud. Conventional decontamination technology yields an oil content in the treated cuttings of >1% in the dried solids, which does not meet strict environmental regulations in many highly ecologically sensitive countries (e.g., the UK and North Sea countries). Apart from cuttings reinjection, all other treatment methods require land-based waste treatment.

Nanoemulsion technology can improve oil-removal efficiency by providing ultralow oil/water interfacial tension (IFT). Heavy- and light-oil extraction from the cuttings surface is enhanced. The cuttings-treatment process proposed in this paper can achieve oil content of <1%.

Nanoemulsion

Nanoemulsions are clear and thermodynamically stable. In typical nanoemulsions, the droplet size ranges from 10 to 100 nm, which is much smaller than the wavelength of visible light. Hence, nanoemulsions generally are weak scatterers of light, making them transparent. Nanoemulsions can be formulated with a single phase or multiple phases. The IFT between the aqueous and hydrocarbon phases in nanoemulsion systems can be as low as 0.0001 mN/m, compared with an ordinary emulsion or macroemulsion (approximately 0.1 to 30  mN/m). A nanoemulsion might be a dispersion of water in oil or oil in water (in which the second solution is the dispersion medium or solvent). There may also be a bicontinuous structure in which both water and oil are continuous.
An Experimental Study of Liquid Loading of Vertical and Deviated Gas Wells
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164516, ’An Experimental Study on Liquid Loading of Vertical and Deviated Gas Wells,’ by G. Yuan, E. Pereyra, and C. Sarica, SPE, University of Tulsa, and Robert P. Sutton, Marathon Oil, prepared for the 2013 SPE Production and Operations Symposium, Oklahoma City, Oklahoma, USA, 23-26 March. The paper has not been peer reviewed.

An experimental study of liquid loading of gas wells has been conducted with air/water flow in a 3-in. pipe at well deviations of 0, 15, and 30° from vertical. A total of 131 tests have been carried out; differential-pressure gradient and liquid holdup were measured. Flow pattern was observed, and critical gas velocity, which defines the threshold for liquid accumulation in a well (commonly termed liquid loading), has been identified.

Introduction

During the production of gas wells, liquid loading is considered one of the most important production problems. Symptoms of liquid loading include liquid slugging at surface equipment, declining or erratic water- and gas-production rates, and dramatic changes in wellhead pressure. Left unchecked, the water accumulation in the well increases the backpressure against the reservoir and provides a damage mechanism by saturating the near-well region with water.

Critical gas velocity is the key parameter in describing liquid loading. There are three definitions of critical gas velocity used in the literature:

The minimum gas velocity at which the largest liquid droplets entrained in the gas core can be transported upward, as used in the criterion of Turner et al. (1969).

The gas velocity at which the flow pattern changes from annular flow to intermittent flow.

The gas velocity at which liquid film starts to move up the pipe wall continuously.

The Turner et al. criterion has been used widely in the industry to predict critical gas velocity for the past several decades. This criterion is based on a force balance on a single droplet entrained in the gas core. It was proposed that the gas well loads up when the entrained droplet moves downward, which is called droplet-flow reversal. Turner qualified the use of the model by stating that the velocity result should be increased by approximately 20% to ensure liquids do not accumulate in the well. The Turner et al. droplet model is based on a vertical configuration and does not include the influence of well deviation on critical gas velocity. This may explain the poor behavior of the Turner et al. model on field data from deviated wells.

The liquid-loading mechanism is still under debate. The majority of existing models are modifications of the Turner et al. droplet model, each with some degree of success in matching the field data. However, film-flow reversal now seems to be the main mechanism, on the basis of observations in the most recent experimental studies. This criterion is adopted in this study to describe the loading initiation in vertical and deviated wells.
Hydraulic Fracturing: History of an Enduring Technology
Authors: Montgomery Carl T. , Smith Michael B.
Published: February 2015

Hydraulic Fracturing

Editor’s note: In 2006, SPE honored nine pioneers of the hydraulic fracturing industry as Legends of Hydraulic Fracturing. Claude E. Cooke Jr., Francis E. Dollarhide, Jacques L. Elbel, C. Robert Fast, Robert R. Hannah, Larry J. Harrington, Thomas K. Perkins, Mike Prats, and H.K. van Poollen were recognized as instrumental in developing new technologies and contributing to the advancement of the field through their roles as researchers, consultants, instructors, and authors of ground-breaking journal articles.

Following is an excerpt from SPE’s new Legends of Hydraulic Fracturing CDROM, which contains an extended overview of the history of the technology, list of more than 150 technical papers published by these industry legends, personal reflections from a number of the Legends and their colleagues, and historic photographs. For more information on the CDROM, please go to http://store.spe.org/Legendsof-Hydraulic-Fracturing-P433.aspx.

Since Stanolind Oil introduced hydraulic fracturing in 1949, close to 2.5 million fracture treatments have been performed worldwide. Some believe that approximately 60% of all wells drilled today are fractured. Fracture stimulation not only increases the production rate, but it is credited with adding to reserves—9 billion bbl of oil and more than 700 Tscf of gas added since 1949 to US reserves alone—which otherwise would have been uneconomical to develop. In addition, through accelerating production, net present value of reserves has increased.

Fracturing can be traced to the 1860s, when liquid (and later, solidiﬁed) nitroglycerin (NG) was used to stimulate shallow, hard rock wells in Pennsylvania, New York, Kentucky, and West Virginia. Although extremely hazardous, and often used illegally, NG was spectacularly successful for oil well “shooting.” The object of shooting a well was to break up, or rubblize, the oil-bearing formation to increase both initial flow and ultimate recovery of oil. This same fracturing principle was soon applied with equal effectiveness to water and gas wells.

In the 1930s, the idea of injecting a nonexplosive ﬂuid (acid) into the ground to stimulate a well began to be tried. The “pressure parting” phenomenon was recognized in well-acidizing operations as a means of creating a fracture that would not close completely because of acid etching. This would leave a flow channel to the well and enhance productivity. The phenomenon was conﬁrmed in the ﬁeld, not only with acid treatments, but also during water injection and squeeze-cementing operations.
Global Unconventional Gas - It Is There, But Is It Profitable?
Authors: Holditch Stephen A. , Madani HusamAdDeen
Published: February 2015

Management

Gas reservoirs are often classified as conventional or unconventional. Conventional gas reservoirs are characterized by high permeability with the gas stored in sand or carbonate formations in pore spaces that are interconnected. A gas resource is generally considered conventional if it does not require a large stimulation treatment to be able to produce oil and gas at economic flow rates. An unconventional gas reservoir can be defined as a natural-gas reservoir that cannot be produced at economic flow rates or in economic volumes unless the well is stimulated by a large hydraulic fracture treatment, a horizontal wellbore, or multilateral wellbores (Holditch, 2006). The three most common types of unconventional gas resources are tight sands, coalbed methane, and gas shales. 

Unconventional gas reservoirs are characterized by low permeability, in the microdarcy range (Fig. 1) or less. As the permeability deceases, the economic risk of developing the resource increases, and the investment required also increases because more wells have to be drilled to produce the reservoir, as each well recovers less gas per well than one can recover per well from a conventional reservoir.

The US Department of Energy’s (DOE’s) Energy Information Administration (EIA) defines the total natural-gas resource base as all of the gas that has ever been trapped inside the Earth, including the volumes that have already been produced. The part of the total natural-gas resource base that interests investors most, however, is the remaining natural gas waiting to be extracted. Research indicates the existence of large, unconventional gas reservoirs located throughout the world. Rogner (1997) estimated that there are 9,000 Tcf of original gas in place (OGIP) reserves in coalbed methane, 16,000 Tcf of OGIP in shale gas, and 7,400 Tcf of OGIP in tight gas sands around the world (Table 1).

Since Rogner published his paper, the oil and gas industry has discovered enormous volumes of natural gas in unconventional gas reservoirs in North American and in several other basins around the world. It is believed that the OGIP estimates in Table 1 are very conservative. The industry will be updating the values in Table 1 and it is expected that the values of OGIP will increase substantially.

With declining conventional gas reserves in the United States, unconventional gas reservoirs are emerging as critical energy sources to meet the increasing demand for energy. The US DOE April 2009 report, Modern Shale Gas Development in the United States: A Primer, stated that over the last decade, production from unconventional resources in the US has increased almost 65%, from 5.4 Tcf/yr in 1998 to 8.9 Tcf/yr in 2007. This increase in production indicates that approximately 46% of today’s US total gas production comes from unconventional resources (Navigant 2008).
Total Spreads Its Wings
Authors: Sheehan John
Published: February 2015

Company Profile Series

Editor’s note: This is the fourth in a series of profiles of leading operators, including key international and national oil companies, around the globe. The focus is on the company’s strategic direction, relationship to its government, major upstream activity, and significant technology challenges and applications.

Integrated French energy giant Total is continuing to spread its wings as it focuses on liquefied natural gas (LNG), deep offshore developments, and heavy oil. The company is seeking to maximize production from its existing fields, while at the same time boosting output from a raft of new projects it is bringing on stream over the next 5 years.

Total has ambitious plans to grow oil and gas output by 2% per year and it is trying to strengthen its upstream arm through exploration, partnerships, and targeted asset deals.

Total is the fifth-largest publicly traded integrated international oil and gas company in the world and is divided into three business segments—upstream, downstream, and chemicals. It produces oil and gas in more than 30 countries, including Angola, Australia, Nigeria, Algeria, Canada, China, Russia, and Qatar.

Production of liquids and natural gas was 2.36 million BOEPD in the second quarter of this year, up 8% from the second quarter 2009, while total 2009 output was 2.28 million BOEPD. The company estimates that the share of gas in production will increase from 44% in the first half of 2010 to 46% in 2014.

Yves-Louis Darricarrère, president of Total’s Exploration & Production Division, said: “Total E&P wants to grow profitably and be one of the best of the majors. To achieve this objective, Total must maximize production from existing fields. This is being done by improving recovery rates from mature fields and by extending production plateaus. Technology and investment are the keywords here.”

He said the company plans to bring on stream a large portfolio of projects and that startups between 2010 and 2015 will account for 880,000 BOEPD of production (i.e., approximately 33% of Total’s production in 2015).

The main startups between 2011 and 2014 include Trinidad Block 2C, Islay in the North Sea, Usan and Ofon 2 offshore Nigeria, Halfaya in Iraq, Angola LNG, Bongkot South in the Gulf of Thailand, and Kashagan Phase 1 in the Caspian Sea off Kazakhstan.

“We must also focus on reserves replacement,” he added. “This means renewing Total’s portfolio by focusing on organic growth (ongoing exploration, access to discovered resources opportunities awaiting development), and completing it with selective acquisitions.”
Technology Focus: Reserves and Asset Management (December 2010)
Authors: Hinkle Delores
Published: February 2015

Technology Focus

Reserves and resource estimation and asset management continue to be oil- and gas-industry topics with a high degree of interest. Asset management has evolved from simply making a decision about when to abandon an operation into a complex integrated evaluation of well, reservoir, and facility performance that includes continual real-time data collection and analysis. Complex fields, sophisticated completion techniques, and challenging economics combine to require detailed, ongoing asset management to achieve maximum asset value.

Reserves- and resource-estimation research has been dominated in recent years by the introduction of the SPE Petroleum Resources Management System and the US Securities and Exchange Commission’s modernized rules. Efforts within the last year have broadened to topics not affected by reporting regimes: to issues such as estimation of reserves and resources in unconventional plays and the application and use of probabilistic assessments. Explanations of the underlying concepts and properties improve, clarifying the reserves- and resource-estimation process and the ultimate use of the volumes for both external reporting and internal planning.

With both topics, the themes of flexibility and continuous improvement are repeated in numerous contexts. The papers summarized in this section represent only a small subset of the many informative papers presented recently and available from OnePetro.

Reserves and Asset Management additional reading available at OnePetro: www.onepetro.org

SPE 133768 • “Development and Application of an Improved Workflow for Developed-Reserves Forecasting” by P.A. Lyford, SPE, Santos Ltd., et al.

SPE 134602 • “A Process To Evaluate Unconventional Resources” by Phillip Chan, SPE, AJM Petroleum Consultants, et al.

SPE 128834 • “Well- and Reservoir-Management Project at Salym Petroleum Development” by Andrew Mabian, SPE, Salym Petroleum Development, et al.

SPE 128542 • “Greater Plutonio—Real-Time Reservoir Management in a High-Cost Deepwater Environment” by Dave Booth, SPE, BP plc, et al. (See JPT, September 2010, page 43)