bluuebunny/crossref_metadata_2025_split huggingface dataset:
Creating a Universal Standard for Evaluating Reserves
Authors: Ritter John 
Published: February 2015

SPE has been a leader in developing petroleum reserves and resources definitions that have become the industry standard for evaluating petroleum reserves, providing a sound basis for improving the consistency in reserves and resource estimation and reporting worldwide. Now SPE is taking another step forward, envisioning a universal standard that could be adopted by international financial, regulatory, and reporting bodies, as well as the oil and gas industry. Forming the foundation for this standard are the petroleum reserves definitions approved in 1997 by SPE and the World Petroleum Council (WPC) and the resources definitions approved by SPE, WPC, and AAPG in 2000.
This effort is being led within SPE by its Oil and Gas Reserves Committee, of which I am honored to serve as Chairperson. Our goal is to review the existing set of definitions and guidelines in light of those current best practices that provide professionals with a common understanding of reserves and resource classification and terminology. Any potential changes should result in a more accurate global picture of current prospects and future energy supplies for the public. In the absence of a comprehensive and current code, individual countries and companies are using their own reserves evaluation systems, making global comparisons difficult.
This update is part of SPE’s ongoing effort to achieve worldwide use of standard reserves definitions. SPE’s Oil and Gas Reserves Committee has helped create some of the most significant industry reference documents on reserves that are in use today (see documents at www.spe.org). This standing committee is made up of 11 members who have reserves expertise and represent a wide geographic cross section. Six observers from a diverse group of societies and agencies also provide other industry perspectives and guidance to the committee.
The reserves committee completed the first phase of the definitions review by producing a glossary that provides a common and consistent understanding of terms. This glossary required several years of work to create, and it was posted on the SPE website in January 2005 (available at www.spe.org/spe/jsp/basic/ 0,,1104_1730,00.html).
The committee is now focused on comparing or “mapping” the classifications and definitions that are used in other worldwide systems for regulatory government reporting or company internal resource asset management. These are the U.S. Securities and Exchange Commission; U.K. Statement of Recommended Practices; Canadian Security Administrators; Russian Ministry of Natural Resources; China Petroleum Reserves Office; Norwegian Petroleum Directorate; U.S. Geological Survey; and the United Nations Framework Classification. By understanding the relationships between these different sets, it will be possible to identify and leverage best practices that could potentially be incorporated into a new set of definitions. The committee made a report on the mapping process at the SPE Board of Directors meeting in October, and the Board approved posting the mapping document to the SPE website.
Overview: Horizontal and Complex Trajectory Wells (November 2005)
Authors: Stone Charles R. 
Published: February 2015

Since the early 1980s, directional-drilling technology has become a vital tool for the drilling engineer. Supporting technologies such as the measurement-while-drilling, pressures-while-drilling, wire-line-steering-tool, and, as of late, rotary-steerable systems allow custom design of target intercepts. Directional-wellbore-profile types now include the build-and-hold, S-curve, horizontal, multi-lateral, radial drilling from a lateral, and “sump drilling,” which creates a “belly” or curved section vertically deeper than the reservoir total depth of the well. Sump drilling uses a pump in the belly portion to aid production and is specifically used for formations that contain heavy oil or that experience impeded formation feed-in.
Regardless of which wellbore profile is chosen for development of the target reservoir(s), burning questions often go unanswered. How much target exposure is too much? How far should the lateral be extended before overextending the economic ability to recoup the investment? To answer these questions, mechanical aspects and production limits must be considered in addition to economic limits. The length of an extended-reach well may be limited by torque and drag or wellbore stability. The length of the lateral in a horizontal well in a 1-darcy-permeability sand may be production-tubing limited. The expense of drilling a 500-ft lateral in such a high-permeability sand may create the same production rate and ultimate recovery as a 1,500-ft lateral in the same target.
Specific answers appear to be woven into the fabric of each directional application. Some parameters include matrix permeability, relative mobility of the produced hydrocarbon or water, wellbore stability, pressure drop from lateral toe to heel, production-tubing size, target pore pressure, anticipated depletion limits of the target formation, and existence of fractures or faults within the target. A thorough examination of all the appropriate factors may reveal a surprising truth: less exposure to the target may be better.
Available from the SPE eLibrary: www.spe.org
SPE 89848 “A Novel Approach to Production Logging in Multiphase Horizontal Wells,” by Vu-Hoang, D., SPE, Schlumberger, et al.
SPE 92685 “U-Tube Wells—Connecting Horizontal Wells End to End Case Study: Installation and Well Construction of the World’s First U-Tube Well,” by Lee, D., SPE, Landmark Graphics Corp., et al.
SPE 93986 “Evaluation of Two-Phase IPR Correlations for Horizontal Wells,” by Kamkom, R., Texas A&M U., et al.
SPE 94945 “A Quantum Leap in Horizontal Gravel-Pack Technology,” by Mendez, A., SPE, BJ Services Co., et al.
Available at the OTC Library: www.otcnet.org
OTC 17548 “New Technology Applications To Extend Field Economic Life by Creating Uniform Flow Profiles in Horizontal Wells: Case Study and Technology Overview,” by Ratterman, E.E., Baker Oil Tools, et al.
Overview: Gas Production Technology (November 2005)
Authors: Wichert Edward 
Published: February 2015

Imagine: gas production without any liquid water. Gas producers would not have to contend with corrosion of tubing strings, formation of hydrates, and loading up of wells with water, which inevitably leads to premature stoppage of production. The handling of gas production at the surface would also be much simpler. Unfortunately, all gas production entails the production of minor, intermediate, or large amounts of water. This problem presents many challenges for research scientists and field operators.
Gas wells producing from reservoirs with underlying water usually will experience increasing water production, which may shorten the productive life of the wells. Water-shutoff treatments with cement squeezes usually are attempted to eliminate, or substantially reduce, the influx of formation water. Currently, much research is ongoing, with different gels aimed at reducing water production.
Hydrates can be a problem in cold climates and in offshore gas production. The conventional method for prevention of hydrate formation in the past has been methanol injection to lower the hydrate-forming temperature. The new approach is to add chemicals to the production that either delay or prevent the agglomeration of hydrates. Hydrates also are being looked at in a more positive light as a future source of gas production, or perhaps as a means for gas storage or transportation in the form of hydrates from areas of surplus to areas with demand for natural gas.
As pressure declines in a gas well, the well will reach some point at which it will be unable to lift the water to surface. Research in this area provides new analytical tools to predict when remedial action will be required to prolong well life.
These topics and others dealing with gas-production technology were addressed in the papers presented during the past year at various SPE meetings. A sampling is presented in this issue.
Available from the SPE eLibrary: www.spe.org
SPE 94081 “A Systematic Approach to Predicting Liquid Loading in Gas Wells,” by Guo, B., U. of Louisiana at Lafayette, et al.
SPE 93544 “Evaluation of Multiphase-Flow Correlations for Gas Wells Located Off the Trinidad Southeast Coast,” by Persad, S., SPE, BP
SPE 93075 “New Technique for Evaluating Antiagglomerate Gas-Hydrate Inhibitors in Oilfield Applications,” by Oskarsson, H., Akzo Nobel, et al.
Technology Update: Haradh III: A Milestone for Smart Fields
Authors: Saleri N.G. , Al-Kaabi A.O. , Muallem A.S. 
Published: February 2015

The Haradh III project came on stream in February 2006, adding 300,000 B/D of Arabian light crude production capacity to Ghawar, the world's largest oil field. The project's main significance, however, derives from the fact that it sets a milestone for smart technologies at a scale and complexity unprecedented for Saudi Aramco and, arguably, for the industry. Haradh III might be regarded as the entry point to a new era in upstream projects and specifically into the domain of real-time reservoir management. The project spanned a period of 21 months. It entailed construction of a grassroots surface-facility network, integrated with a complex subsurface development program. Maximum-reservoir-contact (MRC) wells, smart completions, geosteering, and i-field features provided the four main technology components. Their efficient integration was the key to the project's success.

Background
Haradh constitutes the southernmost portion of the Ghawar complex and covers an area 75 km long and 26 km wide at its widest section (Fig. 1). The field consists of three subsegments of approximately equivalent reserves, with an aggregate oil initially in place of 38 billion STB. Initial production from Haradh I occurred in May 1996, followed up by Haradh II and Haradh III in April 2003 and February 2006, respectively. The field developments, occurring over a span of a decade, offer a unique opportunity in gauging the impact of technologies, the main thrust of this article. Haradh I was developed exclusively with vertical wells, whereas horizontal completions provided the primary configuration for producers/injectors in Haradh II. Haradh III, the main focus here, was developed by relying mainly on smart MRC completions within an i-field framework (Fig. 2). The total Haradh production capacity is 900,000 B/D, with equal contributions from the three respective subsegments I, II, and III.
Arab-D, the producing horizon, belongs to the lower member of the Arab formation of the Jurassic period. It is characterized by a complex sequence of anhydrite and limestone events, with varying degrees of "'dolomitization'." Faults, fractures, and fracture swarms were known to be part of the regional geology and attracted considerable attention in the project planning, given their propensity for creating water-encroachment problems.

Project Statistics
Table 1 presents the key project statistics for Haradh III. It entailed a production target of 300,000 B/D, using 32 multilateral wells. A peripheral water-injection program (with an ultimate capacity of 560,000 BWPD) preceded the crude production by 4 months as part of the planned pressure-maintenance program.
Chinese Firms Emerge as Formidable Competitors in Global E&P
Authors: Ward Richard H. 
Published: February 2015

Guest editorial
When I first came to work in the People's Republic of China back in 1979, domestic production exceeded demand by a comfortable margin. Although production has risen steadily over the past three decades, China has been consuming more oil than it produces since 1993. In 2007, China consumed about twice the amount of oil it generated (BP 2008). Meanwhile, demand continues to grow. How are Chinese oil firms trying to meet the nation's surging energy requirements?

Expanding Domestic and International Activities
China's three main state-owned oil companies—Sinopec, China National Petroleum Company (CNPC), and China National Offshore Oil Company—are fully integrated upstream and downstream, and now compete with one another both domestically and internationally. Domestically, they have explored every viable sedimentary basin in China, using an increasingly sophisticated arsenal of oilfield technologies. Over time, China's oilfield service companies have acquired tools and equipment comparable with those available anywhere else in the world. Like other countries, China's remaining reserves have become more difficult to find, often in deeper or subtler plays, hostile terrains, and environmentally sensitive areas. As seismic and drilling technologies have evolved, Chinese oil firms have gone back and re-evaluated many old fields with new methods and fresh ideas. Reservoirs considered marginal or unproductive in the past are yielding additional reserves.
Nevertheless, demand continues to outstrip China's domestic capacity. As a result, the Chinese have been moving into virtually every key oil and gas province in the world, either as an active player or a nonoperating partner. China's oil companies have forged deep relationships with the major international oil companies (IOCs) and the big oilfield service providers both at home and abroad. They have proven themselves competent peers of the IOCs, and have partnered successfully with many national oil companies.
Chinese seismic and drilling contractors pride themselves on being able to perform efficiently in a variety of remote and hostile regions. For example, BGP, CNPC's geophysical service company, operates more than 100 crews in 24 countries in terrain as diverse as mountains, deserts, gravel plains, jungles, swamps, marshes, shallow water, and transition zones. Since 2006, they have been operating offshore as well (BGP).
In general, Chinese state-owned enterprises appear willing to accept higher risks than some of their international counterparts. Leveraging their association with the government, they have entered a number of situations that the IOCs might normally avoid. If they believe there is significant potential to be exploited, these Chinese companies carefully analyze their options and when they decide to act, they go full speed. This, of course, is providing China with important opportunities to fill its domestic energy needs.
Observations From a Tight-Gas-Reservoir Stimulation
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 117570, "Observations From Tight-Gas-Reservoir Stimulations in the Rocky Mountain Region," by Erik Borchardt, SPE, Schlumberger; Jessica Cavens and Craig Wieland, SPE, EnCana Oil and Gas; and Brian Pluemer, SPE, Don Graham, Abdunnaser Erwemi, Alexei Kazantsev, SPE, and Joel Le Calvez, SPE, Schlumberger, originally prepared for the 2008 SPE Tight Gas Completions Conference, San Antonio, Texas, 9-11 June. The paper has not been peer reviewed.
Unconventional tight gas reservoirs are made economical through effective stimulation techniques. Hydraulic-fracture mapping combined with an in-depth knowledge of reservoir geology and geomechanics can provide a better understanding of the effectiveness of reservoir stimulation. Massive hydraulic fractures from two wells in the Rocky Mountain region were mapped in real time with a 3D stimulation-viewer soft-ware package. One well used techniques standard to the area, while some experimental fracture techniques were tested on the other.

Regional Background
The area of study included 3,000 vertical ft of fluvial and marine sands in the Rocky Mountain region of the US. The formation contains natural fractures, laterally restricted lenticular sandstones, and tight brittle sands. The main natural-gas reservoir interval is from 5,000 to 8,500 ft. The productive sands have an average porosity of approximately 7%, and permeability is in the µd range. The first well was drilled in this region in 1955. In the late 1990s, the discovery of increased production resulting from fracturing lenticular sands made this a profitable area. Wells currently are drilled on 10-acre density. Much of the area uses directional drilling from well pads to reduce surface damage.

Pad Layout
On the study pad, there are four S-shaped wells (Fig. 1). The middle well (Well A) was used as the monitoring well, and the wells directly north (Well B) and directly east (Well C) were stimulated. Wells B and C are approximately 1,200 ft from the monitor well in the vertical section that was stimulated. Well C was considered the control well, while some experimental fracture techniques were used in Well B. Offset to the south of the monitor well (Well A), a series of openhole (OH) logs was run to help understand formation characteristics. A pulsed-neutron tool was run in all four wells so that geological modeling from OH logging on Well D could be projected to all wells on the pad by means of a neural network. The two treatment wells (Wells B and C) had 11 and 12 stages stimulated, respectively. Perforations were designed as 10 sets of perforations per fracture stage. The fracture stages ranged from 180 to 350 ft of net pay.
Application of Invert-Emulsion Drilling Fluid and Aqueous Completion Fluids for Long Multilateral Wells
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 121905, "Design and Application of Invert-Emulsion Drilling and Aqueous Completion Fluids for Long Horizontal Multilateral Wells," by Alistair Hutton, SPE, Stephen Vickers, SPE, Marcus Davidson, SPE, and Jon Wharton, SPE, Baker Hughes; Andy Hatch, SPE, and Roger Simmonds, SPE, E.ON Ruhrgas UK North Sea Ltd.; and David Brankling, SPE, OCTL, originally prepared for the 2009 SPE European Formation Damage Conference, Scheveningen, The Netherlands, 27-29 May. The paper has not been peer reviewed.
The first dual-lateral well aimed at carboniferous reservoirs drilled in the UK southern North Sea was in the Rita gas field. This method enabled both the east and west fault segments of the field to be produced from the same upper wellbore, thus reducing drilling costs and improving field economics. An invert-emulsion drilling fluid was chosen for this field application because of the risk of shale instability over the long horizontal sections of each wellbore.

Introduction
The industry has experienced lower-than-expected production rates from wells that have been suspended for long periods with oil-based, solids-laden fluids before a cleanup has been initiated. This raised the question of what type of fluid to leave below the whipstock because re-entry to this leg for cleanup or well remediation was not economically feasible if production was lower than expected. Because of the diametrically opposed shape of the well, with long horizontal sections, the drilling team was strongly in favor of using an oil-based reservoir drill-in fluid (OBRDIF). This fluid would give a stable wellbore and provide a low friction coefficient for drilling and running the completion assemblies.
Using OBRDIF would reduce the risk of hole instability and minimize non-productive time. However if OBRDIF was used in the drilling phase, it would mean that a solids-laden invert emulsion would be left in the hole when the first leg was suspended with the sand screens below the whipstock. This presented several risks. The fluid would require fine screening to prevent blocking the completion equipment with drill solids. Also, there was a risk that the solid particles in the suspension fluid would agglomerate as the fluid remained static for an extended period. If agglomeration did occur, these solids would probably not pass through the mesh of the completion screens and could potentially reduce screen conductance. The size and concentration of the solids in the suspension fluid were recognized as areas of concern that should be addressed to ensure maximum productivity of this well.
Quantifying the Invisible: Getting a Handle on Methane's Climate Impact
Authors: Beckwith Robin 
Published: February 2015

Earlier this year, a Cornell University professor made quite a splash publishing a paper asserting that emissions from shale gas rivaled those from coal. A July 2011 study issued by the Post Carbon Institute underscored this conclusion. Not so, say five separate recent reports—from Carnegie Mellon University, IHS Cambridge Energy Research Associates (CERA), the US National Energy Technology Lab-oratory (NETL), Argonne Laboratory, and Deutsche Bank Climate Change Advisors (coauthored by individuals from Worldwatch Institute and ICF International). At heart are issues related to measuring and quantifying emissions of an odorless, colorless gas—methane (CH4)—considered the second-most prevalent long-lived greenhouse gas after carbon dioxide (CO2).
The conventional wisdom is that natural gas is “cleaner” than coal. This is indisputable when considering its combustion. For an equivalent amount of heat, natural gas combustion produces about 30% less CO2 than petroleum combustion and about 45% less CO2 than coal combustion. However, the contention these studies wrestle with is that the release of methane during the life cycle associated with natural gas extraction—including drilling, hydraulic fracturing, completions, production, processing, and transport—could be great enough to outweigh this benefit.
Why Atmospheric Methane Matters
According to the Fourth Assessment Report of the Intergovernmental Panel on Climate Change (IPCC), issued in 2007, “over the last 650,000 years, ice core records indicate that the abundance of CH4 in the Earth’s atmosphere has varied from lows of about 400 ppb during glacial periods to highs of about 700 ppb during interglacials.” In 2005, the report states, the global average abundance of CH4, measured at a network of 40 surface air flask sampling sites in both hemispheres, was 1,774.62 ±1.22 ppb. It would thus appear that present atmospheric levels of CH4 are unprecedented in at least the last 650,000 years. According to figures released by the US National Oceanic & Atmospheric Administration, CH4 is responsible for 18% of global warming since the beginning of the Industrial Revolution, while CO2 is responsible for 64%.
According to Martin Heimann in Enigma of the Recent Methane Budget, published in the 11 August 2011 issue of Nature, “About 60% of global methane stems from human activities. This includes emissions associated with energy production and usage—such as coal mining, incomplete combustion of fossil fuels, and gas leaks. These fossil-fuel-derived emissions, together with methane from landfills, organic waste, cattle raising, rice agriculture, and bio-mass burning, were probably the main cause of the increasing concentrations after pre-industrial times.”