bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Update: New Intelligent Completion System Enables Compartment-Level Control in Multilateral Wells
Authors: Dyer Stephen , Bouldin Brett 
Published: January 2017

Technology Update
Although early inflow control devices and intelligent completions (ICs) were introduced almost 20 years ago, completion technology has not kept pace with advancements in drilling technology.
Today, wells completed in multilayered reservoirs, multilaterals with compartments of varying pressure, and extended-reach drilling (ERD) with wellbores as long as 12 km are becoming common. In complex, hard-to-reach reservoirs and tighter formations, operators need to maximize reservoir contact in every well to optimize reservoir drainage and minimize costs. Yet the evolution of ICs has lagged, creating a technology gap with significant ramifications.
IC reliability has been steadily increasing over the years, reaching more than 97% for the life of the well in many applications. Most permanent downhole monitoring and control solutions still consist of a separate “kit” of products rather than an integrated system.
Traditional IC systems lack sufficient real-time measurements in individual producing zones to facilitate “cause and effect” decision making. Without detailed compartmental information and control in case of water or gas breakthrough, operators are forced to restrict production, intervene, and in some instances work over the entire well.
Until recently, there has been no way to maintain production from other unaffected zones during the long diagnostic process of production logging, well testing, interpretation, and execution of an appropriate well intervention. The typical optimization cycle substantially raises operating costs while delaying vital production for weeks or months. Consider Saudi Aramco’s experience with ICs in remote oil fields, where tight formations and a shortage of suitable surface locations drove the need to dramatically increase reservoir contact per wellhead.
Before 2007, the company had successfully drilled and completed a number of multilateral ERD wells, achieving more than 5 km (16,400 ft) of reservoir contact per well. These maximum reservoir contact (MRC) wells were completed with then state-of-the-art IC technology. Completions consisted of permanent downhole gauges (PDGs) and downhole flow-control valves (FCVs), which could be partially or fully opened or closed by hydraulic control lines from the surface. Monitoring and control stations were installed in the motherbore above the junction to each side lateral.
Scaling Up Smart Water
Authors: Rassenfoss Stephen 
Published: January 2017

Middle East Special Section
For nearly a decade, Saudi Aramco has been studying how altering the chemical makeup of seawater injected into its reservoirs can increase production. The result is an increasingly complex view of the interactions caused by the makeup of seawater that explains why seawater does more than just add pressure and help sweep the remaining oil out of a reservoir.
The goal is to cost-effectively maximize production by altering the chemistry of seawater. Hundreds of technical papers have been written on the potential benefits of reducing the salinity in seawater injected into formations.
More recently there has been a growing body of work on how other ingredients found in seawater—particularly sulfate, calcium, and magnesium—can add to oil output by freeing oil from reservoir rock.
Saudi Aramco has focused its research, dating back to 2008, on how seawater is able to increase production from carbonate reservoirs. Two recent technical papers from Saudi Aramco show that it has begun considering how it might modify its water treatment system to turn seawater into “smart water” (SPE 179564), and also offers an update on laboratory studies investigating how the active ingredients in seawater affect oil production (SPE 179590).
What is clear from those papers and other sources is that seawater, which Saudi Aramco turned to as a cheap option to scarce fresh water, can enhance the amount of oil ultimately recovered from the ground. The research also suggests that it can make seawater more effective by altering its chemical makeup, turning it into smart water. But this option is neither simple nor cheap.
Reducing the salinity of the extremely salty seawater used by Saudi Aramco would require desalination on a massive scale. Further changes to make it smart water add processing steps and may require new technology to reduce the energy required and to overcome the fact that available water treatment methods were not designed to selectively remove ingredients from water.
Turning seawater into smart water is a logical next step for the company, which has long been processing seawater on a huge scale to maintain production from its fields. Its Al-Qurayyah Sea Water Plant processes millions of barrels a day of seawater, removing small particles, microorganisms, and oxygen. Now the company has begun considering whether to add further processing steps to apply what it has learned about seawater chemistry by fine-tuning the makeup of the water.
Partnership Key to ADNOC’s Technology Qualification Initiatives
Authors: Whitfield Stephen 
Published: January 2017

Middle East Special Section
As the oil price downturn continues to impact market stability, and its older reservoirs produce diminishing returns in the face of high energy demands, the Abu Dhabi National Oil Company (ADNOC) has recently focused on new technology development and qualification as a key function of its operations moving forward.
One such initiative aimed to develop ADNOC’s technological goals is a collaboration with BP to form an earth surface technology center in Abu Dhabi. And, in seeking to boost recovery from its assets and meet its production targets, the company created its own standards for qualifying new technologies, thus helping it realize strategic production targets and lower overall development costs. Based on the qualification standards of other operating companies and the US National Aeronautics and Space Administration (NASA), ADNOC’s standards on new technologies is set to deploy by the end of the year.
Earth Surface Technology Center
BP and ADNOC have collaborated on a number of joint venture projects recently, including technological initiatives. BP sends employees to Abu Dhabi to provide technical and managerial support to ADNOC and its operating companies. And last year, at the Abu Dhabi International Petroleum Exhibition and Conference (ADIPEC), the two companies announced the signing of a memorandum of understanding (MOU) for the development of a center for earth surface technology. The center aims to help improve the optimization and management of oil reservoirs and increase extraction of oil and gas from hydrocarbons in the emirate of Abu Dhabi, the largest of the seven emirates comprising UAE. The MOU was a result of technical discussions which began between the companies in 2014.
Under the terms of the MOU, BP will provide technical assistance to ADNOC for setting standards for works and products, which will be aimed at improving performance through the enhanced oil recovery technique.
India Road Tests Its E&P Growth Plan
Authors: Rassenfoss Stephen 
Published: January 2017

Mike Watts is the cofounder of Magna Energy, an exploration and production (E&P) startup with no operations and a contrarian business strategy targeting Indian oil and gas.
At a recent presentation in Houston promoting India’s upcoming bid round of small field discoveries, Watts, who led Cairn Energy’s exploration program when it made big deals and discoveries in India, played up the country’s unrealized oil and gas potential.
“You need to be passionate and believe in the geology of India,” Watts told the 150 people who attended the road show publicizing the bid round. Based on his experience dating back to the 1980s, he believes India “is vastly unexplored compared to the potential.”
His vision has the backing of Carlyle Group, a private investment bank, which committed up to USD 500 million to support Magna’s program to build production and reserves in India.
The upbeat mood of the road show contrasted with the dark mood of the current global oil business. India is “a big growing market which is a bright spot in an unsettled world economy,” said Dharmendra Pradhan, India’s minister of Petroleum and Natural Gas.
The sale is an early test of Indian Prime Minister Narendra Modi’s program to expand domestic oil and gas production, which has included sweeping regulatory changes in the world’s third-largest energy-consuming country.
If the country is unable to increase its flat oil production trend line, the International Energy Agency predicts that India will be importing 90% of its oil by 2040 to meet its needs.
“India has a dependence on imported oil and gas, and a clear policy has been set in place to relieve this dependency and that presents tremendous opportunities in the E&P sector,” said Atanu Chakraborty, director general of the Directorate General of Hydrocarbons, which is running the auction of properties relinquished by the state-owned Oil and National Gas Corp. (ONGC).
Mixed Emotions
Consultants in India agree there is reason to be upbeat about India’s future, but they are feeling the global oil slump.
“The last 18 months have been very hard,” said Ashish Chitale, who runs Praesagus RTPO, the Indian partner for the consulting firm Sierra-Hamilton. “All the excitement is potential excitement.”
Drilling Improvements Work Toward the Perfect Well in the Eagle Ford
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 178897, “Drilling Improvements in Pursuit of the Perfect Well in the Eagle Ford—More Than 52% Reduction in Drilling Time and 45% in Cost in 2½ Years,” by Claudio J. Coletta, SPE, Camilo Arias, and Scott Mendenhall, SPE, Statoil, prepared for the 2016 SPE/IADC Drilling Conference and Exhibition, Fort Worth, Texas, USA, 1–3 March. The paper has not been peer reviewed.
In the Eagle Ford, an integrated approach to engineering and operations was key to optimize performance and improve understanding of the area. Application of technology and standardization of operations resulted in continuous performance improvement. Detailed planning and execution, application of rotary-steerable systems (RSSs), implementation of an optimized casing design, contractor performance management, clear and open communication within the team, and implementation of a performance incentive plan all played a part in the overall drilling-performance improvements.
Challenges
Although drilling operations were under way in the area, it was found that existing drilling practices and designs were not well-suited for this well type. At the start, there was a lack of standardization in planning, execution, and communication between office and field staff. Different rigs were performing the same operation differently. Rig moves from well to well on the same pad took exceedingly long. Well performance was challenged by complicated geosteering approaches, a conventional wellhead that required waiting on cement, low rates of penetration (ROPs) while drilling the curve and the lateral sections, and high pressure and temperature while drilling the production hole. High downhole-tool-failure rates resulted in multiple trips in the production section.
The Importance of Scale-Inhibitor Analysis - A State-of-the-Art Overview
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 179900, “The Importance of Scale-Inhibitor Analysis in Scale Management—A State-of-the-Art Overview To Provide Cost-Effective Scale Control From Simple to Complex Production Scenarios,” by Stephen Heath, SPE, Baker Hughes; Gill Ross, Shell; and Gordon Graham, SPE, and Kirsty MacKinnon, Scaled Solutions, prepared for the 2016 SPE International Oilfield Scale Conference and Exhibition, Aberdeen, 11–12 May. The paper has not been peer reviewed.
The accurate and precise analysis of scale inhibitors plays an important role in making key decisions on the efficiency of scale-squeeze and continuous-chemical-injection treatments. Numerous techniques exist for scale-inhibitor analysis, ranging from the simpler methods to more-complex techniques such as high-pressure liquid chromatography (HPLC) and mass spectroscopy (MS). This paper presents a state-of-the-art review of scale-inhibitor-analysis techniques and describes how these techniques can be used to provide cost-effective scale management.
Introduction
Inorganic-scale deposition is a major problem encountered during production of oil and gas and is often managed by the use of chemical scale inhibitors to prevent scale from forming in the system through continuous chemical injection or by periodic batch squeeze treatments. In most cases, scale prevention through chemical inhibition is the preferred method of maintaining well productivity. Scale-inhibitor squeeze treatments provide one of the more common and efficient methods for preventing the formation of carbonate and sulfate scales in the near- wellbore region, tubing, and topside facilities of production wells.
For any scale-management strategy where squeeze treatments are deployed, the objective will be to achieve the longest possible treatment lifetime to maximize oil production and minimize the number of costly well interventions, especially in complex production scenarios. In order to achieve the required longevity for squeeze treatments, it is essential to use a scale inhibitor that is fit for purpose for the proposed squeeze application (i.e., good scale-inhibition performance, nondamaging, good retention/ release properties, and readily and selectively detected to low levels in produced fluids). Indeed, the accurate and precise detection of the scale inhibitor in the produced fluids to low levels at or below the minimum inhibitor concentration (MIC) is a key factor to enable long treatment lifetimes and prevent wells from scaling.
Plume Modeling Establishes Efficacy, Safety of Gas Extraction From Lake Kivu, Rwanda
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 27247, “Plume Modeling in Lake Kivu, Rwanda, for a Gas-Extraction Facility,” by Timothy L. Morse, Nicolas F. Ponchaut, and Gary N. Bigham, Exponent, prepared for the 2016 Offshore Technology Conference, Houston, 2–5 May. The paper has not been peer reviewed. Copyright 2016 Offshore Technology Conference. Reproduced by permission.
Lake Kivu is unique among East African Rift lakes with high concentrations of dissolved carbon dioxide (CO2) in that it also contains methane (CH4). The dissolved gases constitute a hazard because a vertical disruption of the water could cause gas-laden water to be displaced to shallower depths with lower pressures, allowing the gas to bubble out of solution and triggering a gas eruption. A floating gas-extraction facility has been constructed to extract gas-laden water, separate the methane and some of the CO2, and reinject the degassed water, thus increasing the safety of the lake and simultaneously providing CH4.
Introduction
Lake Kivu sits along the border between the Democratic Republic of the Congo (DRC) and Rwanda, in the Great Rift Valley region of Africa. The lake is approximately 89 km long, oriented in a north/ south direction, and 48 km wide. The lake is at 1460 m above sea level and has a maximum depth of approximately 485 m in its northern basin.
Lake Kivu has an unusual thermal structure. At depths below approximately 80 m, the water temperature increases with depth. However, the water also contains large quantities of dissolved CO2 and salt, with concentrations that increase with depth. The density-increasing effects of CO2 and salt maintain the lake stratification despite the inverted temperature profile.
The density structure of the lake is a series of relatively homogeneous mixed zones separated by density-gradient layers. The major mixed zones, beginning at the surface, are referred to as the Biozone, Intermediate Zone, Potential Resource Zone, Upper Resource Zone, and Lower Resource Zone. The Main Density Gradient separates the Potential Resource Zone from the Upper Resource Zone. The Secondary Density Gradient separates the Upper and Lower Resource Zones.
Blowout Prevention and Relief-Well Planning for the Wheatstone Big-Bore Gas-Well Project
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 174890, “Blowout Prevention and Relief-Well Planning for the Wheatstone Big-Bore Gas-Well Project,” by Eric R. Upchurch, SPE, Sam Falkner, Andrew House, SPE, Chinh Nguyen, SPE, and Ken Russell, Chevron Australia, prepared for the 2015 SPE Annual Technical Conference and Exhibition, Houston, 28–30 September. The paper has not been peer reviewed.
The offshore Wheatstone project in Western Australia uses subsea big-bore gas wells as the preferred method of producing the field. Each of the highly productive wells represents a source of gas that, if accidently allowed to flow unhindered, could present an uncommonly difficult well-control challenge. This paper details the engineering and operational planning performed to ensure that no uncontrolled hydrocarbon releases occur during the execution of the subsea big-bore gas wells and that, if a blowout were to occur, the response to such an event would be sufficient and robust.
Introduction
The Wheatstone high-rate gas-well design, with its 9⅝-in. production conduit, represents the company’s initial attempt at implementing such a well. Because the design team’s combined engineering and execution experience included neither big-bore wells nor reservoirs of Wheatstone’s productive magnitude, well-control expectations were limited to anticipating needing only a single relief well in the event of a blowout. However, upon receipt of dynamic-kill simulations performed by consulting experts in that field, a new reality became obvious. That is, the combination of a large wellbore connected to the multidarcy Wheatstone gas reservoir has the potential to produce at more than 1 Bscf/D if flow is unconstrained; in some scenarios, this could require the use of up to four relief wells simultaneously injecting 15-lbm/gal drilling fluid to regain control.
Analyses suggest that it is improbable that a dynamic kill at Wheatstone can be performed successfully using only a single relief well, given the large diameter of the production wellbore. Therefore, the well-control risk of drilling a Wheatstone well was mitigated not by limiting its productive capacity (i.e., reducing the well diameter) but by (1) optimizing casing-setting depths to minimize the number of required relief wells, (2) designing the well to be completely pressure competent, even if it were totally filled with gas, and (3) formulating a blowout-response plan that is reflective of the complexities of executing a two-well dynamic kill on any of the nine foundation wells drilled at Wheatstone.
Silent waves: On silence, Singapore, and Jacques Rancière
Authors: Cervera Felipe 
Published: January 2017

This article stages the silent adventure of watching theatre about Singapore Malays and reading Jacques Rancière in Singapore. The argument blurs the real and the fictional, the voice of the author with the voice of the spectator, Rancière’s voice with the silence of Maya Raisha, a Malay-Muslim girl. In doing so, the piece seeks to evidence that as a consequence of the regulatory nature of performance in Singapore, more than creating a moment of disruption against the normative sphere, silence evidences the instrumentality that ‘speaking up’ has in the normativity of the city-state. The piece is written as the performative chronicle of an intellectual adventure that took place between 2012 and 2013, when alongside reading Rancière’s work in detail, the author moved to Singapore and watched Teater Ekamatra’s Not Counted (2012) and The Necessary Stage’s Best Of (2012-3).
KEWAJIBAN BANK SYARIAH TERHADAP NASABAH PENYIMPAN DANA AKIBAT INGKAR JANJI MITRA
Authors: Burhanuddin Sisca Ferawati 
Published: January 2017

Islamic Banking is a financial institution using the system for results in return. In shahibul maal of financing that invest capital and mudharib provide capacity and reputation to run the business and share in the results that, if there is a loss shahibul maal will lose their money, and the party will lose his labor mudharib in running the business. The Islamic banks as intermediaries for the parties should be neutral, fair, trustworthy, and responsible in terms of this cooperation.
Method is a normative juridical approach namely legal research focuses on the study of secondary data. To strengthen in order to complement the analysis of secondary data, conducted field research to obtain primary data through interviews.
Efforts are being made if there is a legal relationship three parties namely shahibul maal, Islamic banks, mudharib have indications of a loss is not limited to oversight, but the process of consensus, and Alternative Dispute Resolution (ADR) to achieve the objectives of cooperation in terms of rescue funds shahibul maal and business activities mudharib , Accountability Islamic Bank is the responsibility of the owner of the normative means in terms of funds requested mudharabah bank to channel funds directly to the business partners, the bank responsible for the extent of liability than the Islamic bank that is in the implementation of business partner management. While the moral responsibility must integrate moral values with economic measures based on sharia.
Keywords: Responsibilities, Bank, Sharia, Default.
Preliminary evaluation of the effects of photobiomodulation therapy and physical rehabilitation on early postoperative recovery of dogs undergoing hemilaminectomy for treatment of thoracolumbar intervertebral disk disease
Authors: Bennaim Michael , Porato Mathilde , Jarleton Astrid , Hamon Martin , Carroll James D. , Gommeren Kris , Balligand Marc 
Published: January 2017

Abstract
OBJECTIVE To evaluate the effects of postoperative photobiomodulation therapy and physical rehabilitation on early recovery variables for dogs after hemilaminectomy for treatment of intervertebral disk disease.
ANIMALS 32 nonambulatory client-owned dogs.
PROCEDURES Dogs received standard postoperative care with photobiomodulation therapy (n = 11), physical rehabilitation with sham photobiomodulation treatment (11), or sham photobiomodulation treatment only (10) after surgery. Neurologic status at admission, diagnostic and surgical variables, duration of postoperative IV analgesic administration, and recovery grades (over 10 days after surgery) were assessed. Time to reach recovery grades B (able to support weight with some help), C (initial limb movements present), and D (ambulatory [≥ 3 steps unassisted]) was compared among groups. Factors associated with ability to ambulate on day 10 or at last follow-up were assessed.
RESULTS Time to reach recovery grades B, C, and D and duration of postoperative IV opioid administration did not differ among groups. Neurologic score at admission and surgeon experience were negatively associated with the dogs' ability to ambulate on day 10. The number of disk herniations identified by diagnostic imaging before surgery was negatively associated with ambulatory status at last follow-up. No other significant associations and no adverse treatment-related events were identified.
CONCLUSIONS AND CLINICAL RELEVANCE This study found no difference in recovery-related variables among dogs that received photobiomodulation therapy, physical rehabilitation with sham photobiomodulation treatment, or sham photobiomodulation treatment only. Larger studies are needed to better evaluate effects of these postoperative treatments on dogs treated surgically for intervertebral disk disease.