bluuebunny/crossref_metadata_2025 huggingface dataset:
New Uses Keep Emerging for a Deceptively Simple Pump
Authors: Rassenfoss Stephen
Published: February 2015

Progressing Cavity Pumps

Progressing cavity (PC) pumps have been around too long to be a young technology, but it is still an emerging one.

The history of this rapidly growing form of artificial lift is a study in how a community of users can continue to find ways to adapt a seemingly simple machine that can have a complicated relationship with a reservoir. What started as a better option for pumping cold, heavy, sandy crude in Canada has been adapted for high-volume production of heavy crude in Venezuela, for lifting medium-weight oil mixed with things that other pumps cannot handle well, and pumping water out of Australian coal seams to initiate natural gas production from the thousands of wells in the huge deposits.

All-metal versions are beginning to appear in heavy oil fields, after a decade of development and testing to prove they could work at temperatures far beyond what standard PC pumps could handle.

Pushing the capabilities of these pumps, which cannot reliably handle light oil, will require a new generation of elastomers. This will likely require oil and gas industry users to push chemical makers to develop elastomers with capabilities that go beyond the needs of their biggest customers, auto parts makers who use them for tires and other car components.

Several companies recently have begun trying to persuade users to turn to PC pumps powered by permanent magnetic motors downhole rather than relying on rotating rods powered by sur-face units. The advocates of downhole power, which has been a small part of the business, say it can allow more effective PC pump use and reduce tubing damage caused by long rod strings, which can also come apart.

Innovative new pumps are appearing, with some using the usual materials in surprising ways.

“The manufacturing of PC pumps is growing and I think everybody is trying to push the envelope a lot now,” said Shane Latoski, product manager of Oil Lift Technology, which is part of Dover Corporations’ Norris Production Solutions operation. “There are some interesting things coming through.”

The company is in the middle of a rapidly growing business—PC pump makers are also benefiting from the strong sales of mud motors, which are the different use of the original design. The growth of the PC pump business is an example of the value of adaptive reuse.

While emerging technologies are associated with scientific breakthroughs, mature businesses can find and profit from emerging opportunities that grow out of their normal business, said Pradeep Anand, president of Seeta Resources, a business consultant who has advised companies seeking such opportunities.
Probabilistic Modeling for Well-Construction Performance Management
Authors: McIntosh John
Published: February 2015

Management - No abstract available.
Overview: Horizontal Wells (November 2004)
Authors: Stone Charles R.
Published: February 2015

Overview - No abstract available.
Drilling Fluid Strengthens Wellbore
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 87130, "Drilling Fluids for Wellbore Strengthening," by M.S. Aston, SPE, M.W. Alberty, SPE, M.R. McLean, H.J. de Jong, and K. Armagost, SPE, BP plc, prepared for the 2004 IADC/SPE Drilling Conference, Dallas, 2-4 March.
Data Mining for Zonal Allocation and Increased Production in Kern River
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90266, "Zonal Allocation and Increased Production Opportunities Using Data Mining in Kern River," by Carrie Popa, SPE, Andrei Popa, SPE, and Andrew Cover, Chevron- Texaco, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.
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.”
A Warehouse of Defective Pipe
Authors: Rassenfoss Stephen , Beckwith Robin
Published: February 2015

Pipe repository

What looks like a collection of rusty old pipes in a Houston warehouse is a repository of carefully selected objects cared for as if they were part of a museum. Inside and out of the warehouse, there are tubulars once buried in the ground or laid on the ocean bottom. There are large sections of tubulars with corrosion damage inside and out, dents, tiny cracks, and failed welds.

The collection is at the center of research and development (R&D) work by the Pipeline Research Council International (PRCI), which established the location in Houston in December 2011 to house a growing collection that had been scattered in odd spaces at companies around the world. There are more than 150 examples of real-world pipe selected because they fit into the group’s programs, which are dedicated to developing ways to ensure that pipelines are safer and more reliable, said Mark Piazza, director of pipeline programs for PRCI.

For Steve Banks, product development manager at Genesis Oil and Gas Consultants, this ordinary-looking warehouse is like a “toy cupboard.” It offered him access to one-of-a-kind objects needed to test the progress of a project to commercialize a device being developed by Genesis at its R&D facility at the University of Manchester. What stands out about the new machine is its ability to inspect pipes whose inner walls are covered by waxy buildup or other gunk.

The pipe repository is a tangible sign of the PRCI’s technology development program that users say has helped them get past barriers that are often a dead end for new ideas in the oil business.

PRCI members provided advice to Genesis on what the device needed to do, funding support of 2 years of prototype development access to the repository, where Genesis could evaluate its progress on pipe samples with defects known only to a few within PRCI. “The process is fantastic,” said Banks. “Over a 3-year cycle, we are taking something sitting under a sink in a lab, developing it, patenting it, and deploying it in the field with real live data.”
Development and Field Applications of a Novel NAF in the Gulf of Thailand
Authors: Wilson Adam
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 158680, ’Pushing the Envelope of HT Drilling Fluids: Development and Field Applications of a Novel Nonaqueous Drilling Fluid in the Gulf of Thailand,’ by Kerati Charnvit, SPE, Abhijart Kongto, Fransiskus Huadi, and Sunil Sharma, SPE, M-I Swaco, and Gerard Simon, SPE, Brent Estes, SPE, and Neil Trotter, SPE, Chevron, prepared for the 2012 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 22-24 October. The paper has not been peer reviewed.

A novel nonaqueous-fluid (NAF) system was designed to provide stable rheological properties with a nonprogressive gel structure and very good filtration control and filter-cake quality in wells where the expected bottomhole static temperature (BHST) exceeds 400°F. The fluid was successful in providing wellbore conditions capable of being fully logged and evaluated and, at the same time, providing effective hole cleaning with minimum effect on equivalent circulating density. The fluid has been successful in wells with temperatures from 400 to 428°F and mud weights from 11.7 to 14.5 lbm/gal.

Introduction

Historically, conventional NAF systems have had a good performance record in the Gulf of Thailand, providing the necessary fluid and wellbore stability to achieve successful wireline-logging operations. However, when BHST exceeds 400°F, problems have been reported during wireline-logging operation, including difficulties in moving wireline-logging tools to reach the target depth or even getting stuck, which led to nonproductive time (NPT) or loss of tools in several wells. As a result, a more robust NAF that could help minimize the NPT was requested by the operator because numerous wells being planned would have BHSTs considerably above 400°F. The first approach to solve this issue was to review and modify field engineering practices in an attempt to extend the stability of the conventional NAF formulation; however, it was concluded from this initial study that a novel NAF was required for this ultrahigh-temperature condition.

On the basis of extensive laboratory testing during fluid-system development, it was determined that the combination of a new nitrogen-free emulsifier designed for thermal stability in excess of 550°F and a filtration-control package comprising a synthetic polymer coupled with a modified naturally occurring polymer provided the most stable fluid up to 525°F.

Main Components

Emulsifier. A new emulsifier was developed to withstand ultrahigh temperatures and provide low-viscosity, stable emulsions (i.e., low and flat gel structure). The emulsifier also contributes to high-temperature/high-pressure (HT/HP) filtration control and temperature stability of the system. This emulsifier has another benefit over the conventional amine-based emulsifiers because it does not thermally degrade and release ammonia when exposed to ultrahigh temperatures, even if the temperature limit of the product is exceeded.
Successful Cases of Horizontal-Well Tight-Sand-Gas Development in China
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16824, ’Challenges of Horizontal Wells and Successful Cases for Tight- Sand-Gas Development in China,’ by Jia Ailin, He Dongbo, Jia Chengye, Ji Guang, and Wei Yunsheng, PetroChina, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.

Three observations have resulted from horizontal-well development in the Sulige tight gas field. First, well-location selection should be influenced by detailed geological research. Second, measurement while drilling (MWD) is the most effective technique in enhancing the drilling success rate. Third, stimulation treatments such as multistage hydraulic fracturing are the most effective way for gas wells to increase their deliverability. 

Introduction

Tight sand gas, one of the main types of unconventional gas reservoirs, displays the most rapid development worldwide in recent years, especially since its successful development in the US. Tight gas resources are estimated to be 10 trillion m3 in China alone. China holds a large amount of tight-sand gas resources and has obtained good performance in exploration and production during its 11th Five-Year Plan period. The Sulige gas field in the Ordos basin, the Xujiahe gas field in the Sichuan basin, and the Denglouku gas fields in the Songliao basin all show typically successful exploration and production of tight-sand gas in China. Compared with geological settings and development backgrounds in North America, tight-sand gas in China has differing characteristics, including poorer original gas in place, increased depth, and lower netpay thickness.

For tight-sand-gas development, low economic benefits are the main control factor. High costs in drilling, completion, and fracturing, coupled with low revenues from wellheads, scare investors away. From a technical perspective, low saturation, low production rate, and low estimated ultimate recovery (EUR) are constraints. Thus, technical innovations to improve production level and EUR are necessary. For tight-sand gas in the US, infill drilling was the predominant development strategy in the 1990s. For tight gas wells, drainage areas are usually small, the result of reservoir heterogeneity and poor petrophysical properties. Thus, infill drilling can effectively release the remaining gas left by the primary well pattern. The consequences for infill drilling include more gas derived from the reservoir and more costs associated with drilling and completion. In recent years, horizontal drilling and hydraulic fracturing, especially staged fracturing, have become more frequent. Compared with vertical wells, horizontal wells have the advantage of greater drainage area, which can effectively increase the EUR. Staged fracturing can effectively improve the flow matrix and can increase the production rate; thus, the two main factors causing poor economic benefits and constraining tight gas development can be effectively resolved.
Shared Vision (December 2004)
Authors: Paccaloni Giovanni
Published: February 2015

President's column - No abstract available.
Ahead of the Bit: Managing Geohazards Proactively
Authors: JPT staff _
Published: February 2015

Technology Update - No abstract available.
New Bit Technology Saves Operator U.S. $2 Million Drilling Southern Oklahoma Well
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 87096, "Application of New Impregnated-Diamond- Bit Technology Saves Operator $2 Million Drilling Southern Oklahoma Well," by W.C. West, SPE, B.J. Roy, SPE, and S.P. Knowles, Marathon Oil Co., and B.C. Wiesner, SPE, and M.R. Isbell, SPE, Hughes Christensen, prepared for the 2004 IADC/SPE Drilling Conference, Dallas, 2-4 March.
Integrated CO2-Corrosion and Multiphase-Flow Model
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 87555, "Integrated CO2- Corrosion and Multiphase-Flow Model," by Srdjan Nesic, Shihuai Wang, Jiyong Cai, and Ying Xiao, Inst. for Corrosion and Multiphase Technology, Ohio U., prepared for the 2004 SPE International Symposium on Oilfield Corrosion, Aberdeen, 28 May.
Reservoir/Asset Management: Subsurface-Development Challenges in the Ultradeepwater Na Kika Development
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 16699, "Subsurface-Development Challenges in the Ultradeepwater Na Kika Development," by D.T. Rajasingam and T.P. Freckelton, SPE, Shell E&P Americas, originally presented at the 2004 Offshore Technology Conference, Houston, 3-6 May.
Overview: Bit Technology (December 2005)
Authors: Mensa-Wilmot Graham
Published: February 2015

Drilling programs have become more challenging, regarding depths, well profiles, and formation drillability—in terms of hardness and/or abrasiveness. This situation places a lot of pressure on drill-bit manufacturers because they are expected to develop products that drill faster and/or longer in these harsher environments. To achieve this goal, drill-bit technology must outpace the industry’s performance needs. In addition, engineering services and tools, which enable overall evaluation of a drilling program’s objectives, must be developed.

Traditionally, hard- and/or abrasive-rock drilling have been reserved for impregnated and roller-cone bits. R&D efforts, focusing on these bit types, continue to improve the rate of penetration and durability of impregnated and roller-cone bits, respectively. At the same time, polycrystalline-diamond-compact (PDC) bits also have experienced accelerated technology developments. As a result, the performances of PDC bits, especially in hard and/or abrasive formations, have become effective and highly consistent. In most applications around the world, PDC bits continue to replace impregnated and roller-cone bits—they are drilling faster and longer.

The PDC-bit design process has improved greatly through the use of sophisticated design tools. With these tools, cutting structures can be developed to minimize damaging bit vibrations and/or PDC-cutter wear. Currently, PDC-cutter development also has reached a new level. Impact resistance does not have to be compromised to gain abrasion resistance. Technologies continue to be developed that enable both impact and abrasion resistances to be maximized. In addition, specialized-application tools, which aid in the bit-selection and -evaluation processes, also have been developed.

Shortfalls in bit performance, which may seem insignificant in terms of cost, have drastic effects on overall well costs. Considering the technological advancements that continue to be made in bit development, selecting the right bit has become a very critical investment.

Available from the SPE eLibrary: www.spe.org

SPE 94798 “Drill-Bit Catalog and Bit Index: A New Method for Bit-Performance Evaluation,” by P. Macini, SPE, U. of Bologna, et al.

SPE 91782 “Optimization of PDC-Drill-Bit Performance Utilizing High-Speed Real-Time Downhole Data Acquired Under a Cooperative Research and Development Agreement,” by T.S. Roberts, ReedHycalog, et al.

SPE 93910 “The Trouble With Bits—A Holistic Approach to Drilling Optimization,” by D. Hamer, Halliburton Sperry-Sun, et al.
Petroleum Industry 2020: People First: Excellence and Fairness - Part 1
Authors: Al-Khalifa Abdul-Jaleel
Published: February 2015

It is amazing how all people are attracted to excellence and fairness, reflecting a human unity without regard to colour, race, gender, or religion. However, as much as people are united in admiring fairness and excellence, they sometimes differ in understanding their true meaning and application in real life. This can explain why some people live isolated in their thinking and feelings despite today's fast-growing means of communication. Let's explore an understanding that I hope can be universal and practical. We will then try to apply this understanding to individuals and corporations in our industry.

Let us start with the idea that excellence and fairness are twins; they rise and shine together. This principle applies to individuals, corporations, and industries. Individuals, aspiring to be excellent, can be a change agent within their corporations and the industry at large.

Background

In my November JPT column, I talked about how healthy organizations enjoy an evolving process of technology innovation, cost management, and high productivity. They engage the workforce and utilize their employees' full potential. Healthy organizations also exhibit a very high degree of character and competency at both the individual and corporate levels, as demonstrated in Fig. 1. The increasing challenges of higher demand and stretched human resources will drive organizations to do a better job of engaging their workforce. A corporation's workforce is its foundation for future survival. Industry's focus on research and technology spending will build on this foundation.

Genuine efforts to enhance character and competency must be at both the individual and the corporate level. This month's column focuses on the individual. Individuals at all levels collectively form the character and competency of the entire corporation. Furthermore, it is essential to plant the seeds and anchor high standards of character and competency at the individual level, where ownership and accountability reside.

Let's now discuss how SPE can help enhance the individual's character and competency.

Broaden SPE Focus to Cover People Issues

SPE's historical focus has been mostly on technical competencies. Very few SPE papers have discussed ethics, values, organizations, and leadership. Only one in 100 Distinguished Lecturers over the past few years spoke about ethics with regard to reserves booking. Engineering curricula are almost void of courses on character, values, and ethics. While industry training offers courses and information like Seven Habits of Highly Effective People by Stephen Covey, in general there is a dire need for an immediate focus on this critical area. This explains why 95% of the respondents in the December 2005 SPE survey of members' job satisfaction were in favor of a more SPE focus on people issues.
Lower Tertiary Trend: A Study in the Impact of Advancing Technology
Authors: Langley Diane
Published: February 2015

In 2002, few believed that Lower Tertiary sands would be present, let alone productive. Today these defiant sands are reshaping the industry's appraisal of plays in the Gulf of Mexico (GOM). Back in 2002, supermajor Chevron and independent Devon formed a joint venture to explore and exploit the deep Wilcox formation. According to both, new and emerging technology has been and continues to be the differentiator in both the exploration and exploitation efforts in these deep structural targets and has the potential to create a shock wave on financial portfolios.

The Jack-2 well test took place in the second quarter of 2006 at Walker Ridge Block 758 in 7,000 ft of water, and more than 20,000 ft under the seafloor, breaking Chevron's 2004 Tahiti well-test record as the deepest successful well test in the GOM. Chevron, Devon, and Statoil announced that it was a record-setting production test, with the test representing approximately 40% of the total net pay measured in the Jack-2 well.

National Geographic recently gave an apt description of industry achievement in the Lower Tertiary trend: "…you're looking at where in the GOM to drill an 80- to 100-million-dollar well that will ultimately be the size of a dinner plate [on the seafloor]." And, according to analysts, it equates to spending U.S. $100 million to drill and construct a well in mile-deep water to as deep as 5.3 miles below sea level beneath a salt canopy.

The recent, well-publicized Jack-2 well test is actually the latest of several successes in the play. The Great White and Trident finds by Chevron, located in Alaminos Canyon, were the first, and it is speculated that this trend could extend into the Garden Banks and Green Canyon blocks. "This is truly frontier exploration … pushing boundaries," said Gero Farrugio, Wood Mackenzie Upstream Research Manager for Latin America, the U.S. GOM, and Canada. Other prospects already on record in the GOM Lower Tertiary trend include Cascade in 2002, St. Malo in 2003, the first Jack find in 2004, and Kaskida in 2006. The Jack prospect is located far from any existing platform and pipeline infrastructure.

Farrugio points out that while "the Jack-2 test is the first indicator, it is far from proving commerciality of the play."

The technology that is being brought to bear to realize the potential of the Lower Tertiary trend is the ingredient that has the potential to bring understanding of this play needed for the creation of infrastructure and ultimately to prove commercial viability. Drilling commenced on the Jack-2 well under 7,000 ft of water and continued to a depth of 28,175 ft. At this depth, pressures can reach 20,000 psi and the temperature of the oil is approximately 200°C.
First SPE Russian Conference Attracts Top Names
Authors: Donnelly John
Published: February 2015

The inaugural SPE Russian Oil and Gas Technical Conference attracted top names from the country's premier companies as well as leading industry professionals from around the world. More than 2,000 attended the 4-day event in Moscow in October, which featured nearly 200 technical presentations as well as an exhibition that showcased major service and operating firms.

Highlighting the conference, which bore the theme "Technology for World Class Resources," were four panel sessions that examined the current state of the Russian oil and gas industry, case studies of some of the world's most important fields, academia's relationship to the industry, and legends in Russian oil and gas.

The opening plenary session, focusing on Russia's role in the global energy balance, led off with Valery Isaakovich Graifer, Chairman of the Board of Directors of JSC Lukoil and General Director of JSC Ritek OJSC Lukoil. Graifer, who chaired the conference as well, was joined by speakers from leading Russian and non-Russian firms and organizations, including Lukoil, Gazprom, Rosneft, TNK-BP, Transneft, ConocoPhillips, Schlumberger, Halliburton, and the Russian Federal Energy Agency.

Graifer said it was significant that the SPE conference followed closely behind the recent G8 summit held in Russia, in which world leaders discussed the importance of global energy security. The G8 leaders concluded that energy is the most important force for sustainable development and economic progress, that energy security and the future of the world are inseparable, and that the world will continue to depend heavily on hydrocarbons despite a growing interest in alternative fuels. Russia will play a critical role in ensuring that security, Graifer said, but the country needs additional technology and specialists to help develop its oil and gas industry. This SPE conference is "creating educational wealth" that will benefit not only Russia but the international oil industry as a whole, he said, noting the importance of the participation of the leading companies of Russia and the world in both the technical presentations and the exhibition.

Also helping to open the conference was 2005 SPE President Giovanni Paccaloni, who said the conference represented a milestone in bridging information on technology development with the great Russian oil industry.

SPE's growth in Russia has been pronounced, he said. The first SPE section was formed in 1995. Now SPE has more than 700 members in Russia, as well as 520 student members. SPE also announced at the conference that it is opening a new office in Moscow to strengthen its presence and its programs in the region.

Robert Dudley, President and Chief Executive Officer of TNK-BP, also emphasized the importance of sharing technology. "Through the exchange of ideas and experiences, we all do our jobs better," said Dudley, who joined SPE in 1982 and highlighted the Society's role in technology exchange.