bluuebunny/crossref_metadata_2025_split huggingface dataset:
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.