bluuebunny/crossref_metadata_2025 huggingface dataset:
Oil and Fat
Authors: Barbey Alex
Published: February 2015

Guest editorial

In the oil and gas industry, the “S” is surely the biggest part of the “HSE” equation (health, safety, and the environment) in terms of liability and expense. But a lowercase “h” would better represent the lack of attention paid to health—yet “h” issues kill more people every year in the industry than the “S.”

Twenty years ago, when I started working for the industry, the people in this profession were perceived by the general public as young, dynamic, and healthy—traveling and working in remote places, and leading a glamorous, adventurous, Indiana Jones-type life.

However, the truth is sadly different. When medical professionals in this industry meet, although we are concerned that HIV/AIDS, tuberculosis, malaria, and diarrheal diseases are a problem among our workforce, we are shocked that their effects are minor in comparison with the number-one killer—lifestyle-related diseases. Obesity, in particular, is responsible for the high number of deadly heart attacks among oilfield workers.

The bottom line is that more people from the oil patch are dying from heart attacks today than from vehicle or work-related accidents. In 10 years, if nothing changes, half our workforce will be overweight or obese and at greater risk for experiencing heart attacks, strokes, high blood pressure, type 2 diabetes, high blood levels of artery-clogging cholesterol, respiratory problems, and an increase in certain cancers.

The Root Cause

In a world where 1 billion people are overweight or obese (defined by body mass index; see www.nhlbisupport.com/bmi) and where 20,000 people die each day from heart attacks, the oil and gas industry is faced with a workforce that is only getting older and fatter. A formal health-risk assessment is not required to understand the root cause of the problem. It is a simple case of too much food and not enough exercise!

The people in our industry, although well educated, show little understanding or motivation when told that they need to lose weight—until they have a heart attack themselves or learn of the brutal, unexpected death from cardiac arrest of someone close to them such as a family member, friend, or colleague. Many oil-field workers epitomize the “that’s life” or the “it won’t happen to me” mentality.

People just do not seem to take their health very seriously. They figure that life is too short to not enjoy fatty, high-calorie meals washed down with a few glasses of alcohol or soda. Modifying bad habits is always being put off until a few years from now. It is considered easier to take a medication to reduce blood sugar rather than to decrease consumption of extremely sweet carbonated soft drinks; another medication to reduce cholesterol levels rather than eat less butter, fries, fast food, and processed food; and a third medication to reduce blood pressure rather than lose a little weight by walking and moving more.
Achieving Sustainable, Optimal SAGD Operations
Authors: Acosta Erick
Published: February 2015

Technology Update

To meet the global demand for energy, the petroleum industry has been gradually increasing its development and exploitation of unconventional heavy-oil reserves. The production of heavy oil (broadly defined as having a gravity of less than 20°API) can be profitable, but operators usually generate lower profit margins than in light-oil production because of higher extraction cost, the need for diluents, upgrading cost, and the lower market price for heavier crude oils. Consequently, heavy-oil producers have to manage their assets in a sustainable manner by using the best technology available to minimize their total cost of operation and ensure a timely return on investment.  

The vast majority of the world’s heavy-oil reserves are found in Canada, Venezuela, and Russia. Canada has the largest heavy-oil reserves, approximately 175 billion recoverable bbl trapped in the form of oil sands. Extraction of heavy crude from the sands requires unconventional and unique methods (Farouq Ali 2003). The two preferred production methods are open-pit mining and in-situ processes, with steam-assisted gravity drainage (SAGD) being a commonly used in-situ method. Open-pit mining can be used to extract approximately 20% of the recoverable crude from oil sands, while in-situ methods such as SAGD can be used to produce the remaining 80%. In Canada, that would represent approximately 140 billion bbl.

Open-pit mining is a mature technology with a large environmental footprint, and this method can only exploit resources near the surface. On the other hand, SAGD has a much smaller footprint, even as it unlocks reserves well beyond the reach of mining operations. Thus, in areas such as the Athabasca and Cold Lake regions of Alberta, SAGD operations have been emerging and rapidly expanding. Fig. 1 is an artistic representation of an SAGD facility, including some common injection points for oilfield chemicals. In SAGD, the two most common types of chemical treatments are related to emulsion separation and water clarification for reuse of water in steam generation.
SPE Annual Conference Makes History
Authors: Donnelly John
Published: February 2015

Conference review

SPE’s first Annual Technical Conference and Exhibition (ATCE) held outside the US drew 4,700 oil and gas professionals from more than 70 countries to the historic city of Florence, Italy. Approximately 60% of this year’s attendees came from Europe, the Middle East, Asia Pacific, Russia and Caspian area, Africa, and South America as the event attracted a truly international crowd.

This year’s conference also received 1,800 paper proposal submissions, the most ever for an SPE event. Of those, more than 400 were selected for presentation. More than 250 exhibiting companies from 17 countries showcased new and novel technologies for the E&P industry during the conference as well.

The Chairman’s Luncheon Address and the Opening General Session highlighted the first day of the conference. ATCE 2010 General Chairman Claudio Descalzi, chief operating officer for E&P of Eni, delivered the address to a packed ballroom. His theme was how operating companies must refocus on improving competencies, their relationships with producing countries, and corporate culture if they are to succeed in the future. Over the past decade, the industry has been effective in finding new resources, but not in bringing those resources into production, he said. And with global demand predicted to soar, both international and national oil companies must become smarter, more effective, and more efficient in their operations, he said.

Operators outsourcing technology development to the service sector over the past 2 decades has caused operators to lose some expertise, Descalzi said. Going forward, operators must improve in the following areas, he said:

Raise technological competency and learn how to apply technology more efficiently, and create knowledge-management systems to capture skills needed and lessons learned.

Improve relationships with host producing countries. Technology alone is no longer enough to offer countries with resources.

Instill a meaningful corporate culture. “Laws and regulations change from country to country and from time to time,” he said, but the industry needs a model of common standards, especially in the area of health, safety, and the environment.

“The applications of these three steps will bring many positives to our industry,” Descalzi said, including making it more competent, efficient, and competitive.
The Future Ain't What It Used to Be, Or Is It?
Authors: McIntosh John
Published: February 2015

Management

If a man tells you he knows a thing exactly, then you can be safe in inferring that you are speaking to an inexact man. —Bertrand Russell

In “The Difficulty of Assessing Uncertainty” (SPE 5579, 1976) E.C. Capen described how oilfield engineers struggled to quantify variables. Capen asked groups of SPE members to estimate 10 quantities (e.g., dates, distances, times) using ranges with a prescribed confidence level. What he found (and others before and afterward confirm) is that very few people are good at this exercise.

Probabilistic methods and in particular Monte Carlo Simulation (MCS) are often thought to solve the problems presented by Capen. However, MCS can make matters worse if a misleading estimate appears to be backed up by a detailed process, voluminous research, and specialized software. All estimates need to be calibrated, that is, substantiated by reference to reality.

For clarity, it is worth defining the terms uncertainty and risk. Uncertainty is used here to describe the fact that for any future project a range of outcomes exist. Risk is used to describe less-desirable outcomes; typically risk relates to a project running late and over-budget.

The purpose of this article is to suggest that a calibrated estimate of well project duration and cost should be a standard part of the investment decision-making process. A calibrated estimate will substantiate a wide range of possible outcomes and improve the quality of information available prior to allocating capital. Communicating information related to risk is also an area where the E&P industry can learn from others.

Rating and Describing Risk

Rating systems exist to describe in broad, concise terms the nature of risks associated with particular financial investments. The risk being rated is the less desirable outcome that the borrower defaults on the money invested. Standard and Poor (a credit-rating agency) use the term “AAA” to describe the lowest investment risk to capital. In the Standard and Poor system, 13 basic levels of long-term credit risk are described using a scale from AAA to D.  With the potential project costs faced by the E&P industry, it seems strange that standard tools have not been established so that risk can be measured and communicated.

The credit-risk system has been through a difficult period and is thought to have contributed to a large number of bad investment decisions. The fact that the risk of collateralized debt obligations (CDOs) was thoroughly underestimated reflects badly on the system. But lessons can be learned from the financial industry. First, although the system was flawed, it has not been abandoned and will be improved. Secondly, so much has been written and published about financial risk that it would be irrational not to use knowledge gained from these expensive lessons. Thirdly, the cost of poorly understood risk is illustrated well by public errors such as the CDO fiasco.
Improving Human Resources Through Benchmarking
Authors: Lincoln Darren
Published: February 2015

Talent & Technology

Oil and gas companies are facing human resource (HR) challenges that require a different approach if companies want to be competitive for attracting and retaining talent. SAIC is in its third year of running its Oil and Gas Human Resources Benchmarking Study. The study, organized at the request of two supermajors and a major refiner, focuses on recruitment, retention, the aging workforce, HR costs, and diversity. The following reviews some of those results from the first two studies.

Recruitment and Retention

Recruitment and retention of the right people are vital to the success of the organization; however, common performance metrics for HR groups can work against filling positions with the best candidates. Our study found that HR groups that focus on “time to fill” as a measure of performance have higher first-year separation rates. The correlation was striking with the shortest average time to fill of approximately 30 days having a first-year separation rate of almost 20% (Fig. 1). The company with the longest average time to fill of 120 days had a first-year separation rate of less than 5%. This indicates that companies that spend more time reviewing, interviewing, and vetting candidates have more success keeping those people who are hired.

We found a similar trend when comparing offer acceptance rate to first-year separation rate. Our study shows that HR groups with higher college offer acceptance rates have higher first-year separation rates. At first, this seemed counter intuitive but the trend might be explained by thinking of recruiters as salesman and their product as the company; some recruiters may be overselling and not fully disclosing the details. This trend falls apart when looking at experienced offer acceptance rate. Presumably experienced people are better at selecting and vetting companies before receiving offers.

Two other peculiar correlations we found are:

Companies with higher average tenures have longer time to fill

Companies with a higher percentage of employees more than 50 years old have lower offer acceptance rates
Changing the Safe Drilling Window With Invert Emulsion Drilling Fluids
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 132207, ’Changing the Safe Drilling Window With Invert Emulsion Drilling Fluids: Advanced Wellbore Stability Modeling Using Experimental Results,’ by Terry Hemphill, SPE, Halliburton; William Duran, SPE, Saudi Aramco; and Younane Abousleiman, SPE, Vinh Nguyen, SPE, Minh Tran, SPE, and Son Hoang, U. of Oklahoma, originally prepared for the 2010 CPS/SPE International Oil and Gas Conference and Exhibition in China, Beijing, 8-10 June. The paper has not been peer reviewed.

Often the range in drilling-fluid densities required to prevent hole collapse without fracturing the wellbore (i.e., the safe drilling window) is narrow. This often is the case for wells having high deviation angles, and is of particular concern in extended-reach-drilling (ERD) wells. With increasing stepouts, the drilling equivalent circulating density (ECD) continues to climb with increasing measured depth (MD) while the true-vertical depth (TVD) remains fairly constant. 

Introduction

The drilling of challenging wells often is characterized by a narrow safe drilling window, with the fracture-initiation pressure as the upper bound and the wellbore hole-collapse pressure as the lower bound. For those cases where the collapse pressures are below the pore pressure, the pore pressure then serves as the safe-drilling-window lower bound. The safe drilling window commonly is gauged in terms of equivalent mud weight (EMW) and represents the acceptable range of density for maintaining wellbore stability. When the wellbore is circulated, for example during drilling operations, the EMW is equivalent in value to the ECD. When the wellbore is static, the EMW is equivalent in value to the equivalent static density (ESD). Depending on the downhole pressure and temperature conditions, the ESD often is not equal to the density measured under ambient conditions, especially when drilling with invert-emulsion drilling fluids (IEFs).

In the modeling of stresses around an intact wellbore, the safe drilling window becomes more narrow with increasing hole angle. Specifically, a deviated wellbore profile requires increased EMW to prevent collapse and reduced EMW to initiate fractures. Hence, in ERD wells, the safe drilling window can become very narrow at the higher angles of deviation.

In the drilling of ERD wells having long departures, the ECD will continue to increase with increasing MD, as the frictional pressure produced while circulating increases with hole length while the TVD does not increase by much, if at all. The effect of ECD in these kinds of wells serves to increase the operating EMW to the point where the upper bound of the safe drilling window can be violated and initiation of wellbore fracturing is predicted. Consequently, much effort has been focused in recent years to widen the safe drilling window safely without sacrificing wellbore stability.
Technology Focus: Gas Production Technology (November 2010)
Authors: Wilson Scott J.
Published: February 2015

Technology Focus

Those who cannot remember the past are condemned to repeat it. George Santayana

Rarely a day goes by when a new shale-gas conference is not advertised; each will highlight the rapidly changing state of the art in fractured horizontal wells and shed light on what will always be a very complex and challenging way to complete wells. With increased interest and activity comes the need to evaluate and forecast the performance of these wells accurately with little production history as a basis. This problem has plagued engineers since the first wells were drilled in the 19th century. How does one predict the future of a new kind of well when few examples exist with enough production history to guide the forecast, and the reservoir behaviors are not understood well enough to simulate the performance mathematically?

Lessons from the past may help. Typically, a new play is ignited by an operator that is stubborn enough to keep trying new things while ignoring years of failure and the peer consensus that the operator is crazy. Soon after the secret is discovered, this newly exposed fertile ground attracts other operators desperate for better opportunities. The increased demand for leases, equipment, and services and increased regulation drive the economic returns down, not to mention the glut of production if the play lives up to its promise. Meanwhile, a new set of contrarians will begin to question the assumptions that created the boom in the first place; because rarely is there enough history to definitively prove the long-term outcomes before most have lost interest and moved on to the next hot play.

Buffering this emotional ebb and flow are operators who are not swayed by the prevailing thought. The selections for this month’s feature are examples from those who diligently look for patterns from the past to improve their accuracy in predicting the future.

Gas Production Technology additional reading available at OnePetro: www.onepetro.org

SPE 127919 • “Analysis of Data From the Barnett Shale Using Conventional Statistical and Virtual-Intelligence Techniques,” by Obadare O. Awoleke, Texas A&M University, et al.

SPE 130151 • “Enhanced Gas Recovery—Challenges Shown in the Example of Three Gas Fields” by Torsten Clemens, OMV, et al.

SPE 131714 • “The Permeability Factor in Coalbed-Methane-Well Completions and Production” by Ian Palmer, Higgs-Palmer Technologies
A Compression Strategy for Tight Gas Wells in South Texas
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 124869, ’Low Pressure System for Gas Wells: Do We Need It? How Low Should We Go? A Compression Strategy for Tight Gas Wells in South Texas,’ by Quynhthy Bui, SPE, Larry Harms, SPE, Efren Munoz, SPE, and Joe Becnel, SPE, ConocoPhillips, originally prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. The paper has not been peer reviewed.

In a large field with thousands of wells of different ages and qualities, determining the optimum operating pressure is a challenging task. This study looks at the Lobo field in south Texas, which has approximately 1,800 tight gas wells currently in production, to determine the effect of pressures on recovery and the benefits vs. costs of compression. Wells were divided into three groups that share similar characteristics and were modeled using integrated-production-modeling tools to evaluate recovery vs. line pressure.

Introduction

Initial field development began in the late 1970s. As the field matures, reservoir pressure declines, and as a result, so does production. Optimizing production requires optimizing surface pressures. The continuous drilling program, while adding to potential recovery, exacerbates the optimization challenge because the mixture of older and newer wells has a large range of pressure needs. The long lead time of compression projects, combined with the flow and load-up characteristics of numerous wells, can result in a significant range of uncertainty for design volumes. Timing, location, horsepower, capacity, throughput, and compressor configuration are some of the numerous variables that need to be determined, with constantly changing needs.  Addressing questions on this issue presented a unique opportunity for a multifunctional team of reservoir, production, facility, and operation disciplines to work out a compression strategy. It was necessary for the team to work together to align goals and production philosophy and to manage a balance between top-priority projects in the short term and longer-term projects. A strategy that balances the costs and benefits of compression for the different types of wells was developed. The full-length paper focuses only on the methodology used to determine the benefits and estimated costs of reduction in wellhead pressure, including timing of compression.

Definitions and Descriptions of Process

The general characteristics of the wells were evaluated to determine the best modeling methodology. The wells produce from the Lobo Lower Wilcox sands at depths ranging from 7,000 to 13,000 ft. These are typical tight gas plays, with permeabilities from .01 to 1 md and net pays from 15 to 150 ft. The average production rate per well in the field currently is less than 200 Mcf/D.
Spectrum: Training for Your Future
Authors: Thakur Ganesh
Published: February 2015

President's column

This is a great time to be an engineer. Global workforce changes and other challenges today present tremendous opportunities for personal growth and career advancement. We E&P professionals are witnessing an extraordinary convergence of factors that are reshaping the energy workforce and will profoundly impact our industry and our careers. I would like to share with you my thoughts on this situation and suggest how SPE can help members maximize their opportunities for professional growth.

According to the latest Schlumberger Business Consulting (SBC) HR Benchmark survey,* four global workforce realities are significantly shrinking the availability of technical talent in our industry: the “big crew change,” the shortage of mid-career professionals, the shift to more unconventional oil and gas resources, and post-Macondo regulatory challenges.

The big crew change, long talked about, is now in full swing. An entire generation of Baby Boomers, who entered the work force in the late 1960s and early 1970s, is moving on to other activities. The SBC survey found that about 25% of the current experienced workforce of petroleum engineers and geoscientists is over age 50, with the majority likely to retire in the next 3 to 5 years. This amounts to about 22,000 experienced professionals expected to leave the industry by 2014. The SBC survey also found that graduate schools are expected to replace only about 17,000 of those in that same time period, leaving the industry with a technical talent gap of 5,000 experienced professionals in the next several years.

At the same time, to meet the growing demand for energy, the industry must use ever more complex and sophisticated technologies. That will require that our E&P professionals stay current on the latest technologies and their applications. How can SPE help you respond to these challenges and better enable you to ply your engineering skills in an energy-thirsty world?

SPE does many things extremely well, such as meetings and publications. But there are some areas, such as training and education, where we can focus more attention. That is one area where SPE is already making great efforts. Today, SPE offers more than 80 training courses** to help you solve real-world problems. You can find our courses across the globe, held in conjunction with SPE conferences and workshops as well as at our regional training centers in Calgary, Houston, and Dubai. Courses are also offered in other venues to meet member needs.

** “2010 SBC Oil & Gas HR Benchmark, Schlumberger Business Consulting, March 2011 (www.sbc.slb.com/SBCInstitute).

** See www.spe.org/training/.
Automation Will Drive Industry Revolution
Authors: Bement James
Published: February 2015

Guest editorial

Automation is a leading buzz word in our industry, perhaps to the point of triteness. In order to achieve a significant step change in safety, efficiency, reliability, and performance while addressing a growing demand and reservoir complexity, we must advance just as other industries have. Thankfully, we have the ability to use their insight to drive our own industry’s development, using automation experts and best practices from fields such as medicine, automotive, and aerospace.

We understand the technology necessary for automation: fully automated rigs, smarter sensors and drilling tools, virtual onshore operation centers and detailed subsurface modeling including updates to the subsurface geomechanics, petrophysics and wellbore models in real time. How we will create one automation/control system among competitive industry verticals remains to be solved.

Integration of Industry Verticals? Or Something Different?

The 600-pound gorilla in the room that must be solved is how we will create this system. Open standards are necessary, but not at the expense of competitiveness. Is the answer, then, to acquire and integrate all system components under a single corporate entity? Some have moved in this direction. While this may be a short-term answer, perhaps the long-term solution is not something the industry has yet envisioned: Simply integrating industry verticals will not drive efficiency, as we cannot work in a factory drilling environment with the rigs that exist today, and there are major issues related to liability in terms of control and ownership of these components.

We need innovation to find the right approach. Achieving the next level of integration and drilling efficiency will require a new concept that differs dramatically from the rigs of today. It will mean turning convention on its head and changing our current derrick, drawworks, and mud pumps mind-set. We have many ways to pick things up, to pump, mix and clean fluids, sand and gels as we drill and complete, so the answer for automation may be some combination of current components or something we have not thought of. This system must also be easy to manufacture, rig up and down, and move, and it must have a lower capital cost, a high degree of automation, a step change in operational efficiency, and result in improved safety with fewer people on location.

Added to this is the necessity to solve the completions part of well construction automation. As an industry, we are focused primarily on drilling automation. How do we bring completions into the mix?

The other piece we have not solved is what the digital interface among these activities will look like, that is, what the service delivery platform will be. Today, it is literally the physical rig; the future will be some type of digital platform enabling the most comprehensive system available for drilling for oil and gas.
Technology Focus: Drilling and Completion Fluids (November 2011)
Authors: Estes Brent
Published: February 2015

Technology Focus

When you take a look at the oil industry these days, what is the one thing you hear and read about the most? “Shale plays.” Operators are developing resources, purchasing acreage, and purchasing companies that have acreage in the USA and in countries around the world, now more than ever before.

For long-term economic stability of these projects, they need to be drilled as inexpensively and as fast as possible—basically, they need to be “factory-type wells.” The main fluid-related challenges associated with shale drilling are rate of penetration (ROP), shale stability, torque and drag, and waste management. Many of these wells are being drilled with nonaqueous fluids (NAFs) to meet these challenges, with the only real issue being waste management. However, there are technologies being used that reduce the amount of waste generated with NAFs, such as premium solids-control systems and thermal-desorption methods.

In an effort to eliminate NAF waste-management issues, drilling-fluids companies have developed fit-for-purpose water-based drilling fluids for each of the major shale plays. The shale regions around the world vary in depth, mineralogy, temperature, and other characteristics, and a single fluid formulation does not fit all circumstances. Each fluid is customized to the unique characteristics of a particular shale region. Fluids companies have specific products and chemistries that are designed for a specific type of shale and drilling operation.

As technological advances enable exploitation of shale resources around the world, the challenge will be to find the most-cost-effective solution. As always, the lowest overall well cost may not result from the lowest-cost-per-barrel drilling fluid. One has to take into account ROP, torque and drag, wellbore stability, and waste management when determining the most-cost-effective solution.

There were many good papers written this year, and I have tried to choose a variety of universal topics. Please take time to read them and the papers listed as additional reading.

Drilling and Completion Fluids additional reading available at OnePetro: www.onepetro.org

SPE 144214 • “Crude-Oil-Compatibility Method Significantly Minimizes Volumes Required” by Katrina Schultz, SPE, Baker Hughes, et al.

SPE 142008 • “Chemical Properties Affecting the Environmental Performance of Synthetic-Based Drilling Fluids for the Gulf of Mexico” by P.B. Dorn, SPE, Shell, et al.

SPE 139623 • “Drilling-Fluid Design Enlarges the Hydraulic Operating Windows of Managed-Pressure-Drilling Operations” by Doug Oakley, M-I Swaco, et al.

SPE 139534 • “Preliminary Test Results of Nanobased Drilling Fluids for Oil- and Gasfield Application” by Md. Amanullah, SPE, Saudi Aramco, et al.
Holistic Drilling-Fluid and Waste Management in the Fayetteville Shale
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 144036, ’Holistic Drilling-Fluid and Waste Management in the Fayetteville Shale,’ by Mark Mabile, SPE, and David Richardson, Southwestern Energy, and Steven Garner, Barry Broussard, and Richard Smith, SPE, Performance Fluid Management, 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.

Successful application of a holistic-fluid-management (HFM) program from January 2009 through December 2010 improved drilling-fluid performance and reduced waste and costs in Southwestern Energy’s Fayetteville shale-gas project in Arkansas. The HFM program lowered drilling-waste volumes by approximately 45%, while reducing drilling-fluid and -waste costs by 36%. The reduction in combined costs (i.e., fluid systems, solids-control equipment, and waste disposal) totaled USD 69 million while drilling more than 4,200,000 ft in 705 wells with oil-based mud (OBM) during the 24-month study period.

Introduction

Like most shale-gas projects, the Fayetteville shale requires specific well-construction techniques. Most of the wells drilled during the project period were horizontal, with total measured depths of 8,000 to 9,000 ft with lateral sections approximately 4,500 ft long. On average, 15 rigs were active during 2010, each unit completing approximately 35 wells/yr. During this 24-month study, 1,000 wells were drilled for a total footage of more than 5,700,000 ft. Of these, 720 wells were drilled with oil-based mud (OBM) with a total footage of more than 4,200,000 ft. Fifteen anomalous wells that exhibited severe lost circulation or other problems were excluded from the study. The remaining 705 wells drilled with OBM are the subject of this paper.

Various studies have shown the economic and environmental benefits gained by use of drilling-fluid-management programs for conventional oil and gas plays. Typically, before management programs were applied, procurement of drilling fluids and associated services accounted for 20 to 30% of the combined costs for overall fluid management, solids control, and waste disposal. Reductions in the quantities of chemicals and base fluids used and in waste generated at drilling sites can result in significant cost savings and a reduction in environmental effects.

Drilling-Fluid-Management Considerations

The solid- and liquid-waste streams produced in typical well construction can be grouped into five general categories—cuttings; drilling fluid on cuttings; drilling-fluid dilution, dumping, and tank bottoms; water; and other waste fluids. The aggregate volume of the generated waste typically is 10 to 15 times the overall volume of the hole drilled. The cuttings volume cannot be reduced, but all other waste streams can be reduced.
Drilling With a Balanced-Activity Invert-Emulsion Fluid in Shale: Is It Sufficient for Maintaining or Enhancing Wellbore Stability?
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 145969, ’Drilling With a Balanced-Activity Invert-Emulsion Fluid in Shale: Is It Sufficient for Maintaining or Enhancing Wellbore Stability?,’ by Terry Hemphill, SPE, Halliburton, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed.

Most wellbore-stability problems encountered while drilling occur in shale formations. Invert-emulsion fluids (IEFs) are used to drill reactive shales. Testing of a deepwater shale was performed with a new apparatus, which allows shale samples to be tested under downhole conditions. Results show that even at an activity level higher than the known shale-activity level, water was able to enter the shale and weaken it. The “chemomechanical-balance” concept was used to explain measured results in terms of the coupling of shale-mechanical properties and IEF chemical activity and to explain the resulting consequences of activity-level selection for IEF.   

Introduction

The interaction of invert-emulsion drilling fluids with exposed shales has received much study because well-bore-stability problems occurring in shale are in the 80% range of all cases cited in literature. While usually not found in the reservoir sections, when these shales become unstable, significant nonproductive time is spent in efforts to stabilize the wellbore, and sometimes entire drilling intervals are lost. To understand the interaction of IEFs with shale during the drilling process better, it is helpful to review the pertinent theories used to describe such action.

Semipermeable-Membrane Theory. At the face of the shale that is exposed to aqueous fluid, a semipermeable membrane exists that regulates the flow of water in or out of the specimen. Fluids having high membrane efficiencies, such as IEFs, have the ability to pull water from the rock efficiently. But fluids with low membrane efficiencies, such as common water-based drilling fluids, do not pull water efficiently. There is still uncertainty about whether the membrane is provided by the IEF or by the shale itself.

Osmotic-Pressure Theory. Fluids having lower chemical activity compared with the shale-pore fluid can generate significant amounts of osmotic pressure that can be used to remove water from the rock. Conversely, an IEF with higher chemical activity in the drilling-fluid water phase than in the shale-pore water can push water into a shale.
Drilling Highly Depleted Formations With Engineered-Particle Nonaqueous Fluids: South China Sea
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 139932, ’Drilling Highly Depleted Formations With Engineered- Particle Nonaqueous Fluids: South China Sea,’ by Michael R. Niznik, SPE, Adela Lawrence, SPE, and Sabine C. Zeilinger, SPE, ExxonMobil, prepared for the 2011 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 1-3 March. The paper has not been peer reviewed.

A new engineered-particle nonaqueous-fluid (EP-NAF) system was used in the Malay basin of the South China Sea to drill through highly depleted sands at elevated densities. The fluid contains sized particles to bridge and prop open fractures as they occur during actual drilling operations. Formation integrity is gained immediately and does not require additional critical-path rig time. 

Background and Well-Design Overview

The Malay basin in the South China Sea contains multiple oil and gas accumulations, some of which have been on production for several decades. Many of these mature fields have economically recoverable quantities of hydrocarbons but are challenging because depleted zones are adjacent to formations prone to wellbore instability. A four-well infill development program was planned in one of these mature fields. The field is 200 km offshore in 70 m of water. Several platforms were installed to develop the field, which has been producing for more than 20 years. Typically, tender-assisted platform rigs are used in this field.

Well-Design Challenges and Planning

All proposed wells would be side-tracked from existing donor wellbores. A variety of casing sizes was used in the donors, and exact cement tops were not known. The exact sidetrack point was engineered to take into account collision avoidance of offset wells, cement behind casing, formations in which to sidetrack, and dogleg requirements to meet geology and reservoir objectives.

The target reservoir was the Group-J sands that lie below the Group-I reservoir, which was completed and put on production more than 20 years earlier. The pore pressure of the Group-I reservoir in the area where the proposed wells would penetrate was determined to be depleted to a 3.7-lbm/gal gradient. The target Group-J sands also were slightly depleted to a 6.8-lbm/gal gradient because of production in adjacent fault blocks.

The targeted Group-J reservoir has lower-permeability sands compared with the Group-I reservoir above it. Horizontal wells were planned to intersect additional reservoir footage and to maximize productivity and reserves recovery. The Group-J sands are highly consolidated, and modeling, along with offset-well analysis, determined that sand control would not be required. The wells could be completed open hole with predrilled liners, which minimized completion complexity and cost.
Shallowest Horizontal Well Drilled in the Middle East: Challenges and Successes
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142439, ’Shallowest Horizontal Well Drilled in the Middle East: Challenges and Successes,’ by Abhijit Dutta and Bader M. Al Azmi, Kuwait Oil Company, and Hakim Al Abri, and Musab Ali, Halliburton, prepared for the 2011 SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 25-28 September. The paper has not been peer reviewed.

Major plans are underway to exploit heavy-oil resources in very shallow regions of Kuwait. Drilling horizontal wells poses great challenges in these shallow formations and requires high dogleg severity (DLS) through extremely loose formations while drilling with a conventional Kelly-drive rig. The use of multitier planning and exact execution enabled successful drilling and completion of the shallowest horizontal well in Kuwait on the first attempt.  

Introduction

The Lower Fars is a shallow unconsolidated heavy-oil reservoir in northern Kuwait. The reservoir is mainly in the southern part of the Ratqa field. The lithology sequence from the surface to the Lower Fars includes the surface Kuwait-series sand, which has the Dibdiba freshwater aquifer (approximately 150 to 250 ft deep) and a brackish-water channel just above the shale cap of the heavy-oil-sand strata.

Because the unconsolidated-sand reservoir is at an extremely shallow depth of approximately 700 ft and is in close proximity to infrastructure, it is attractive for exploitation by vertical wells but poses many challenges for drilling horizontal wells with an extremely shallow kickoff point (KOP) and high DLS. More than 75 vertical wells have been drilled, with coring, sampling, vertical-seismic profiling, full-suite logging (including imaging), and extended leakoff testing in many wells to evaluate the friable, unconsolidated, and loose sand. The preferred production method is cyclic steam injection (huff-’n’-puff) to reduce the viscosity of the oil for enhancing production. Both casing strings (surface and production) in all wells drilled at Lower Fars are cemented with thermal cement that can withstand thermal-cyclic stress.

Challenges

Concerns were raised in regard to the technical viability of drilling these horizontal wells with a conventional Kelly-driven rig. A slant rig could eliminate many of the disadvantages expected with a vertical rig. However, the cost of hiring a slant rig and nonviability of deploying a vertical rig for workover operations in slant wells prevented use of this method. The biggest challenges in drilling a horizontal well were to maintain the directional trajectory and to lower the casing and liner by use of a Kelly-driven rig with little weight available. Drilling through shale at a high angle also was perceived as a potential challenge.
Shale Reservoir Evaluation Improved by Dual Energy X-Ray CT Imaging
Authors: Walls Joel , Armbruster Meghan
Published: February 2015

Technology Update

The rise of unconventional shale plays as an economically feasible oil and gas resource has created an unprecedented opportunity and challenge for laboratory core analysis providers. By some estimates, more than 80% of the core samples being extracted from North American fields are from shale formations. Core analysis has become an integral part of most unconventional exploration and development projects because the data is essential to petrophysical interpretation, reservoir modeling, and reserve estimation. A major difficulty facing operators is that shale core analysis conducted by traditional laboratories has been a slow process, with the data sometimes arriving too late for use in time-critical business decisions.

Digital rock physics (DRP) analysis (Walls and Sinclair 2011) offers a faster way of obtaining the needed data for shale reservoir evaluation. DRP analysis of shales usually involves three stages, each providing visual and quantitative information to help select a smaller representative rock volume for the next analytical stage. Stage 1 analyzes whole cores or cuttings; Stage 2 analyzes samples from cuttings to plug size; and Stage 3 analyzes samples at pore scale in 3D with ultrahigh resolution. The process takes only a few weeks for most wells.

In this report, we will examine the first stage of DRP for whole or slabbed core, using the CoreHD technique developed by Ingrain. The method is based on dual energy X-ray computerized tomography (CT) imaging and usually requires only a few days to complete. The technique has also been used at remote drillsites, with the core being analyzed within minutes or hours of being brought to the surface.

Dual Energy X-Ray CT Imaging

As X-ray CT imaging technology improves, so has the value of the data for the oil and gas industry. Beginning in the 1980s, petroleum literature on CT imaging such as “X-ray Computerized Tomography” by S.L. Wellington and H.J. Vinegar (JPT, August 1987) can be found. In the past 2 years, Ingrain has developed and refined a comprehensive workflow to analyze shale core by harnessing the value of dual energy X-ray CT imaging. From X-rays produced at different energy levels, continuous whole core scans can be calibrated to produce bulk density (RHOB) and photo electric factor (PEF) values at about half-millimeter resolution. At this resolution, 1 ft of core scanning produces around 500 CT images. The images show important geological details including fractures, bedding planes, fossils, and bioturbation. The high-resolution computed RHOB and PEF values can be used to interpret porosity, organic content, and mineralogy. When combined with other commonly available information such as core spectral gamma data, more complex analyses can be performed. For example, elastic properties and brittleness index can be determined.
Processing Oil Sands Fluid Tailings by Oleophilic Sieve Technology
Authors: JPT staff _
Published: February 2015

Young Technology Showcase

This article describes the merits of commercializing a modern oleophilic sieve for the removal of bitumen and oleophilic minerals from the fluid tailings of mined oil sand tailings ponds. The process is extremely fast, with low power and thermal-energy requirements. It separates the tailings cold and only heats the bitumen-phase product to make it easier to pump. Scale up is simple and the cost of commercial equipment is expected to be low. Both fresh and mature tailings may be handled by the process without dilution.

Currently, the oil sands industry squeezes some water out of fluid tailings by layering these, and then proposes to remove the discarded bitumen later before transferring the tailings to permanent storage or remediation. However, for the purpose of bitumen removal, the layering process is not an efficient use of time, requiring careful review by oil sands operators.

Dispersed bitumen and oleophilic minerals are components that many researchers believe prevent dewatering of tailings. Removing these before layering the fluid tailings will yield bitumen of better purity for upgrading; will reduce the release of methane and other gases to the air from the ponds; and will free tailings water faster, resulting in more effective fluid-tailings compaction for permanent storage or for site remediation.

Oleophilic sieve technology works well for both types of fluid-tailings components and effectively removes hydrocarbons that pollute and tend to stunt the growth of many plant species.

The sieve uses an endless cable made from steel or polymer rope looped multiple times in wraps around a separation zone, comprising a revolving apertured drum filled with medium- density balls; and around a bitumen-removal zone, comprising one or more revolving squeeze rollers.

An endless cable is wrapped multiple times around two or more roller supports. Unlike a mesh belt, the modern oleophilic sieve does not have cross members. This improves flexibility and eliminates the need for expensive belt tracking and automatic control of belt alignment. Spaces between sequential cable wraps form the apertures of the sieve and these can be tailored for width to optimize sieving of feedstock of various compositions and temperatures.

A cable guide keeps the wraps from falling off the revolving supports. The wraps walk across the revolving roller surfaces until reaching a roller’s edge, and then the last wrap is guided and redirected to again become the first wrap.