bluuebunny/crossref_metadata_2025_split huggingface dataset:
Increased Oil Production With Something Old, Something New
Authors: Rassenfoss Stephen 
Published: February 2015

Pumping is stopped to allow a pressure test to see if the formation will allow free movement of chemicals used to free the remaining oil in this old Oklahoma field.
Enhanced oil recovery (EOR) has become fertile ground for emerging—and re-emerging—technologies.
Emerging from laboratories are materials based on nanotechnology that could change what is possible with aging reservoirs. Researchers are working on making carbon dioxide foams built to last, time-release coatings to deliver gels deep into reservoirs, and tracers for real-time waterflood tracking.
Re-emerging are chemical EOR methods that have been around for 30 years but whose development was stunted by a long stretch of low oil prices. Higher prices are now inspiring a second look at EOR methods, taking advantage of advances in chemistry and computing to create cost-effective ways to rework underperforming old fields.
“It didn’t happen when the technology stopped developing in the 1980s,” said Jeff Harwell, a professor at the University of Oklahoma, who has been a catalyst for this re- emerging technology. “My perception is we are just to the point in the industry where oil prices have risen to the level where it is economic.”
Continued oil prices near USD 100/bbl makes EOR an attractive possibility—the estimated cost to produce plus the profit margin needed to justify the risk is about USD 60/bbl, Harwell said—but, for the many independents that own older fields, the cost of reducing salinity levels in their fields in order to use the available chemicals has been prohibitively high.
Harwell said he and others he knew in EOR realized that, while the economics once again favored it, work was needed to make EOR a realistic option for small and mid-sized operators whose budgets and appetite for risk are both limited. They worked with chemical companies to develop improved surfactants that worked without having to make costly modifications to fields, improved techniques for analyzing and planning EOR projects to increase the chance of success, and started a company to demonstrate what they could do.
He is not alone. Harwell pointed out that others, such as Gary Pope, a professor at The University of Texas at Austin, whom he describes as the EOR guru, is working with a chemical company to create improved surfactants. Big EOR service providers, such as Tiorco and Surtek, are also working on new things.
It is a tough sell, but one with big potential. In Oklahoma, only 14 billion bbl of the 82 billion bbl in the ground have been produced, he said. Many fields date back to the early days of oil exploration when the focus was on pumping oil as fast as possible. “It was really before petroleum engineering was a discipline,” Harwell said. Production was limited by early over-production and poorly done waterflooding experiments, adding to the petroleum engineering expertise required to rework these fields.
Mature Fields Hold Big Expansion Opportunity
Authors: Parshall Joel 
Published: February 2015

Mature fields
While big discoveries and major new developments deservedly grab the headlines, mature fields are the backbone of global oil and gas production. Revitalizing these fields extends their productive lives and offers significant opportunity to expand worldwide reserves.
A 2011 report, “Mature Oil Fields—Unleashing the Potential,” by IHS Cambridge Energy Research Associates, indicated that approximately two-thirds of global daily average oil production comes from mature fields and that the percentage is increasing over time. The report considered fields mature if they had produced more than 50% of their established proved plus probable resource estimates or had produced for more than 25 years.
The term mature field does not have a single definition. Many engineers consider a field mature when production has declined to less than 50% of its plateau rate. Individual companies may apply their own definitions.
“We consider the subsurface and the surface,” said Olivier Heugas, a member of the mature field team at Total’s headquarters near Paris. “For the subsurface, we consider a field mature when the cumulative production has reached 50% of the initial 2P (proved plus probable) reserves. And for the surface, given the aging facilities, we consider a field mature after 10 years of production. So when one of the two criteria is reached, we consider it a mature field.
“There are other criteria we might consider, such as BSW (basic sediment and water) levels or a sharp increase in gas/oil ratio or depletion rate. It is on a case-by-case basis. There have been young fields with these subsurface or surface problems, and other fields that have produced for 10 years without these problems.”
A Huge Global Resource
Regardless of the definition, mature fields are a huge global resource. With reserves categorized as proved or probable, attempts to expand reserve levels come at a relatively low risk. Modest additions to a base of this size can be very substantial.
Data Mining Applications in the Oil and Gas Industry
Authors: Abou-Sayed Ahmed 
Published: February 2015

Data mining and analytics
The recent proliferation of resources exploitation, in both traditional and unconventional basins, has led to more upstream oil and gas industry activities in more regions than ever. These newer activities, when added to the already challenging work environments in such frontiers areas as deep water and the Arctic, place tremendous demands on the industry to work more efficiently and avoid risks to people, capital, and the environment. An emphasis on monitoring and assurance of the production operations during exploitation has caused the oil and gas industry to enter the digital age during these last two decades in a grand way and has generated what the information technology (IT) industry calls “big data.” Data acquisition in instrumented wells and monitoring of fields and operations processes are routinely carried out in both real-time and post-mortem modes. Management and use of this big data have become critical for the industry and its stake holders, including regulators and financiers. Integration of data analytics into the practice of petroleum engineers is essential to establishing a vision for the oil and gas industry to move toward data-based decisions in the production and operations arena.
The largest amount of computing power in the industry so far has been dedicated to the collection and storage of information (databases and warehousing) as a result of the low cost and portability both of electronic sensors and computer memory. Great emphasis has been put on automated reporting, standardized presentations, and streamlined data transfer to cut costs for data processing and dissemination. Even when no immediate need for the data was present, the low cost of data collection has driven company decision makers to support data storing and sorting for later analysis.
Current databases contain transactions that can be stored and retrieved without relying on employees’ memories. Unfortunately, while information banks are full, clients are not communicating efficiently and data sharing sometimes is inhibited by the size of the specialized warehouses. Integration of the data and coincidence of the information seen by all team members across the organization has been lacking. The more serious gap in this digital age has been in the transformation of this data into information and knowledge that could drive management actions or become the basis for corporate-level decisions.
Improving Horizontal Completions in Heterogeneous Tight Shales
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146998, ’Improving Horizontal Completions in Heterogeneous Tight Shales,’ by Roberto Suarez-Rivera, SPE, Chaitanya Deenadayalu, Maxim Chertov, SPE, Ricardo Novalo Hartanto, SPE, and Patrick Gathogo, Schlumberger, and Rahul Kunjir, University of Utah, prepared for the 2011 Canadian Unconventional Resources Conference, Calgary, 15-17 November. The paper has not been peer reviewed.
Production from nanodarcy-range-permeability shale formations requires extensive hydraulic fracturing, large volumes of water, and closely spaced wells. Comparing calculations of the possible fracture-surface area created during treatments to production results indicates that a large portion of that surface area is ineffective for production, resulting in ineffective use of resources. A fundamental understanding is required to improve the efficiency of horizontal completions in producing shales. The objective of this study was to improve completion design and horizontal-well-completion efficiency.
Introduction
When considering tight-shale-formation characterization and completion design, one should evaluate the formation characteristics conducive to economic production: reservoir quality (RQ), representing the multiple properties defining reservoir potential, and completion quality (CQ), representing the multiple properties defining the potential for creating and sustaining a large surface area in contact with the reservoir. RQ and CQ properties vary in the near-wellbore and far-wellbore regions. For CQ, the far-wellbore region represents the region of contact between the created fracture and the reservoir. Well production depends on this surface area being in contact with good RQ, and depends on conditions of containment, fracturability, rock/fluid interactions, and loss of surface area and fracture conductivity during production. The near-wellbore region represents the choking point between the created surface area and the wellbore. The goal is to maximize connectivity between the fracture system and the wellbore. This goal is attainable by minimizing near-fracture tortuosity, maximizing fracture width, reducing breakdown pressures, and limiting the risk of solids production. The result is a nonsubjective and consistent method that provides a means for understanding variability in fracture performance along wellbores (e.g., inferred from microseismic monitoring, trace analysis, and stage-by-stage flow measurements) and for selecting perforation stages on the basis of measured or log-inferred rock properties. The method also provides a means for monitoring consistency between the predicted values and measured results.
Sanding Prediction Validated by a Perforated Test in a Sandstone
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 158255, ’Sand Prediction by Different Criteria and Validation by a Perforated Test in a Sandstone,’ by Y. Wang, SPE, Petro-Geotech, and E. Papamichos, SPE, Sintef Petroleum Research, prepared for the 2012 SPE Heavy Oil Conference Canada, Calgary, 12-14 June. The paper has not been peer reviewed.
Sand production from a perforated sample was determined by the onset of a significant discrepancy between strains in orthogonal directions. The onset was analyzed with three sanding models—shear-failure, cohesive-tensile-failure, and effective-plastic-strain (EPS) models. The EPS model provided results closest to testing. Equivalent plastic displacement (EPD) is proposed as an additional critical parameter that enables determining the sanding onset directly.
Introduction
Predicting sanding is increasingly important in completion and production engineering. If the sanding point is surpassed, engineers must determine if, when, and what sand-control strategy is required, and these determinations critically affect the decisions regarding the type of completion selected, such as fracturing, horizontal well, open hole, or cased hole. Engineers also need to evaluate the benefit of oil-production enhancement if no sand control is implemented. All these issues can depend on the accuracy and reliability of the sanding prediction. Even though a Mohr-Coulomb (M-C) criterion is used widely for the critical-shear-failure or sanding conditions, it has been considered too conservative; therefore, a Lade model is proposed.
Study
Three criteria, reflecting different sanding mechanisms, are applied extensively to sanding problems in the field, and, consequently, different critical sand pressures or drawdowns are generated. Use of these criteria to determine the sanding point from a single test or field condition can yield more questions than answers; therefore, defining an adequate criterion could be quite helpful. The use of stress-oriented criteria usually is simple, requiring fewer parameters, but such criteria can be too conservative, and, more importantly, those required parameters cannot be measured and monitored directly. The models used with stresses often are determined statically (i.e., they cannot be linked uniquely to the deformation), whereas extensive deformation can be linked proportionally to sanding, which is essential to determine the critical point both physically and mathematically. Another issue of the use of stress-oriented criteria defined by the M-C and cohesive-sanding models is that the parameters cannot be measured or monitored in the laboratory or in the field; instead, they are acquired from an indirect strength measurement because stresses or strengths can only be interpreted, not measured. Alternatively, a deformation-related criterion is proportional to well unloading and the required input can be monitored and measured directly.
Data From Above: The Advantages of Unmanned Aircraft
Authors: Jacobs Trent 
Published: February 2015

Unmanned Aerial Vehicle Technology
Making them fly was the easy part. Making them useful was the next challenge. And now unmanned aerial vehicles (UAVs) are being put to the test to determine where they are the most applicable to the oil and gas industry. Companies and university researchers developing these “flying computers” believe that their sector is ready to rapidly expand, because of recent technological advancements and legislation that will open up the unmanned skies in the industry’s largest potential market by 2015: the United States.
UAVs are already being used by some oil and gas companies to inspect flare stacks and track migrating wildlife and ice floes in the Arctic. In the near future, UAVs will be used as important tools to respond to oil spills and pipeline monitoring, and in offshore installation and decommissioning operations.
A few years ago, the militaries of the world held a virtual monopoly on the application of UAV technology, and UAVs available to the private sector were little more than eyes in the sky with limited functionality. Today, commercial UAVs are the benefactors of miniaturized electronics, partly thanks to the smartphone industry and advanced software programs specifically designed to make sense of the different types of data that can be gathered while flying. Equipped with lasers, high-definition cameras, thermal imaging systems that can “see” at night, and an array of other sensors, advocates of UAVs claim they are not simply cheaper alternatives to fixed-wing aircraft and helicopters, but in many ways are more capable and, without question, safer to operate.
Last fall, BP completed an experimental flight in Prudhoe Bay, Alaska, using a quadrotor UAV developed by Canadian-based Aeryon Labs. Quadrotor UAVs, also called quadcopters, use four rotors to lift and move the aircraft and are known for their maneuverability. At the time, US authorities were only issuing flight certificates to determine the airworthiness of UAVs without allowing commercial operations. BP completed the test run to determine how Aeryon’s UAV could inspect oilfield equipment and pipelines to assess maintenance needs.
Developing Flank Areas in a Giant Carbonate Field With Horizontal-Well Placement
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 161591, ’Development of Flank Areas in a Giant Carbonate Field With Optimal Placement of Horizontal Wells,’ by Sameer Khan, SPE, Ali Al-Shabeeb, Zankar Jani, Yousef Azoug, Nguyen Minh, and Harshad Patel, SPE, Zakum Development Company, prepared for the 2012 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed.
Successful development of flank areas depends on accurate reservoir characterization—in particular, water-saturation distribution—in addition to the optimal areal and vertical placement of wells. In relatively thin reservoirs, horizontal wells are generally preferred to increase reservoir contact; the proper spacing and vertical placement of these wells are critical. To test the initial concept in the field, two existing producers were converted into injectors, and pressures were monitored at the offset producers.
Introduction
The subject oil field is one of the world’s largest offshore carbonate reservoirs and has a production life in excess of 100 years. The field was historically developed with wellhead tower platforms made of steel structures and a combination of vertical and 1-km-long horizontal wells in a five-spot pattern. A new development plan was proposed in 2008 that deployed artificial islands as drilling centers and used extended-reach- drilling technology. In addition, well counts were significantly reduced by deploying longer (3-km) horizontal laterals, referred to as maximum-reservoir-contact (MRC) wells. The development plan comprised both surface and subsurface components, which were effectively integrated to provide maximum flexibility in terms of development options as well as handling of reservoir uncertainties. Because the aquifer support for the subject field is weak, the development consists of a waterflood with line drive to be followed later by gas injection. This island-based plan was approved by shareholders in 2008, and implementation began soon thereafter.
The development plan includes a comprehensive subsurface development scheme based on the available data and prediction tools. Development-plan optimization soon began as more data were being acquired and new reservoir models were built. This work is focused on development-plan optimization of two large flank areas of the largest reservoir in the subject field (south and east flanks in Fig. 1). These flank areas contain very large capillary transition zones that, although only a few hundred feet high, extend to several kilometers areally because of very low reservoir dip (1 to 2°) in a 150-ft-thick reservoir. Therefore, appropriate areal and layer placement of MRC wells in flank areas is a critical task that requires careful attention.
Fracturing-Treatment Design and Reservoir Properties Impact Shale-Gas Production
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16400, ’Analysis of the Impact of Fracturing-Treatment Design and Reservoir Properties on Production From Shale-Gas Reservoirs,’ by C.E. Cohen, C. Abad, X. Weng, K. England, A. Phatak, O. Kresse, O. Nevvonen, V. Lafitte, and P. Abivin, Schlumberger, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.
This paper sheds light on the nonlinear physics involved in the production of shale-gas reservoirs by improving the understanding of the complex relation between gas production, reservoir properties, and several treatment-design parameters. The authors ran 28 simulations to cover the 2D parametric space of proppant size and fracturing-fluid viscosity for a range of parameters (detailed in the complete paper). More than 1,400 simulations were run in this parametric study, and the results provide guidelines for optimized treatment design.
Introduction
Production from shale-gas reservoirs depends greatly on the efficiency of stimulation. The accumulated experience in our industry with the technique of hydraulic fracturing has led to best practices in treatment design that have contributed to the rapid increase in productivity of shale-gas wells over the last decade.
The objective of this paper is to present a parametric study on the relation between the parameters of a treatment design and the production outcome based on numerical simulation. To generate an extensive number of simulations, the workflow is automated with a script that sequentially runs all the simulation cases, archives the results, generates visualization outputs, and creates a simulation report. This method enables more than 100 simulations overnight, depending on the complexity of the cases.
The methodology used in this study begins with constructing a base case built from the Marcellus shale data. The outputs for each set of simulations are accumulated production after 6 months, 1 year, and 3 years; total propped length and average propped conductivity are regarded as a function of both proppant size and fluid viscosity. A total of 1,467 cases was simulated for this parametric study (see the complete paper for a full discussion of results of these simulations).
Base Case
For the base case of this parametric study, permeability is 200 nd and the horizontal stress anisotropy is 1%. The conductivity of unpropped fractures is fixed at 0.001 md-ft. The completion is a horizontal well, and the base case is a single stage of pumping through four perforation clusters that are 100 ft from each other.
The treatment is made up of 224,576 gal of fracturing fluid and 183,700 lbm of proppant pumped at 80 bbl/min. The schedule begins with 18% of pad followed by slurry with a proppant concentration of 1 ppa. For simplicity, the fracturing fluid is assumed to have Newtonian rheological behavior.