bluuebunny/crossref_metadata_2025_split huggingface dataset:
Overview: Drilling Technology (February 2008)
Authors: Menand Stephane 
Published: February 2015

Overview
An increasing number of superlatives are used to describe challenges that the drilling industry faces. Indeed, adjectives such as high, extreme, long, ultra, severe, or extra are used quite often to qualify the complexity of wells drilled today or that will be drilled in the near future. To name a few, one hears about ultradeep offshore, ultradeep drilling, ultraslim tools, very-extended-reach drilling, high-rate data transmission, ultrahigh torque connections, ultrahigh-strength steel, high-accuracy measurement, very advanced modeling, high-definition visualization, high-performance, and many others. Drilling becomes less and less conventional in terms of materials, techniques, data acquisition, and transmission systems and turns into unconventional or extreme drilling by use of new technologies and operating limits.
Another observation is that the drilling industry attempts to combine and integrate several drilling techniques and methods, not only to overcome the difficulty and complexity of drilling deeper, longer, and in higher pressure and temperature in a severe downhole environment, but also to extend the production of mature or depleted fields. For example, it is not rare to combine coiled-tubing drilling with underbalanced-drilling methods, or an ultraslim rotary-steerable system with a casing-while-drilling (CWD) system. There is talk about combining CWD technology with expandable tubulars. In brief, complex-drilling challenges will find their economic and engineering solutions by mixing several high-level technologies.
Papers presented on the following pages and in the additional reading illustrate these technology trends.Ultradeep or extra-long drilling requires increasingly higher-strength drillpipe and advancements in material to reach the target successfully and safely.Drilling technology must be accompanied with realistic and advanced modeling or laboratory experiments to obtain better benefit from and understanding of complex hydraulic and mechanical phenomena.New managed-pressure-drilling methods are required to compensate dynamic pressure in reservoirs having a low margin between the fracture- and the pore-pressure gradients.
Drilling Technology additional reading available at the SPE eLibrary: www.spe.org
SPE 110708 "Case Study: Drillstring-Failure Analysis and New Deep-Well Guidelines Lead to Success" by David R. Bert, SPE, BP plc, et al.
SPE 107903 "Implementation of a Shock- and Vibration-Mitigation Process: Achieving Real-Time Solutions and Savings" by Goke Akinniranye, SPE, Schlumberger, et al.
SPE 107547 "Improved Drilling-Process Control Through Continuous Particle and Cuttings Monitoring" by T.H. Omland, Statoil, et al.
SPE 109530 "The Extraction of Mud-Stuck Tubulars Using Vibratory Resonant Techniques" by Ozzie Gonzalez, Vibration Technology, et al.
Determination of Cuttings Lag in Horizontal and Deviated Wells
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 109630, "Determination of Cuttings Lag in Horizontal and Deviated Wells," by Augusto Garcia-Hernandez, SPE, Stefan Z. Miska, SPE, Mengjiao Yu, SPE, and Nicholas E. Takach, SPE, U. of Tulsa, and Claudia Zettner, SPE, ExxonMobil, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11–14 November.
The objective of this study was to determine experimentally the cuttings lag or slip velocity in horizontal and high-angle boreholes. Cuttings lag is a critical component of an accurate determination of the source depth of the cuttings. Unique experiments were conducted at simulated downhole conditions by use of a flow loop with a transparent 8×4 1/2-in., 100-ft-long annulus.

Introduction
Cuttings transport is an important part of the drilling process. Numerous experimental studies have been performed to investigate factors related to cuttings removal from the wellbore. Drilled cuttings are an excellent source of information about a drilled formation. However, this information can be used efficiently only if particular samples of rock can be assigned to a specific location. Accurate models of cuttings transport should be used to estimate the difference in the time required for drilling mud and cuttings to reach the surface from the same location.

Model Development
The development of a lag diagram and model begins with derivation of relationships between the current position of the drill bit and the source depth of cuttings collected at the surface. In these relationships, cuttings velocity is the most important parameter to be calculated for horizontal, inclined, and vertical configurations. A lag diagram results from the cuttings velocity and derived relationships for the cuttings source depth.
Using known drilling parameters such as bit depth and rate of penetration (ROP) and making certain assumptions, the relationship between cuttings source depth and current drill-bit position can be derived. Derivation of the lag-diagram-model relationship is presented in the appendix of the full-length paper.
Fig. 1 shows a schematic of a vertical wellbore. Cuttings appearing at the surface originated from the source depth A. Since these cuttings were drilled, time has elapsed and drilling has progressed a distance F to the bit depth DC. A cuttings-source function is given by Eq. 1 in the full-length paper and is used to relate the position of the drill bit with the cuttings source. Evaluating this function for different drill-bit positions produces a lag diagram.
Erha Floating Production, Storage, and Offloading Vessel
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18659, "Erha and Erha North Development: Erha Floating Production, Storage, and Offloading Vessel," by S.M. Day and G.J. Parker, ExxonMobil, and P. Barclay and H. Boulais, Saipem, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May.
The new-build Erha floating production, storage, and offloading vessel (FPSO) is one of the largest in the world, at 285 m long by 63 m wide, with a 2.2-million-bbl-capacity hull and capacity for 210,000 B/D oil processing, 340 MMscf/D gas injection, and 150,000 B/D water injection. The full-length paper discusses the development of the FPSO, including design and operational features incorporated to meet field-specific requirements. The paper also addresses the project-management challenges associated with each phase of the job, with emphasis on the safe and timely execution of a sequential drill center startup while managing simultaneous production operations and in-field development drilling.

Introduction
The Erha and Erha North development, in 1200 m of water approximately 97 km offshore Nigeria, consists of three subsea drill centers tied back to the FPSO by steel catenary risers (SCRs). Injection fluids are transferred from the FPSO by the SCRs and flowlines for subsea injection at the drill centers.
The FPSO is a new-build, spread-moored vessel consisting of two trains of three-stage oil separation. Processed crude is stored in the hull and offloaded regularly to tankers through offloading lines and a catenary anchor leg mooring (CALM) buoy. Associated gas is compressed and dehydrated to provide fuel gas, with the remainder reinjected into the producing reservoir. Water injection facilities inject treated seawater into the reservoir for pressure maintenance to enhance oil production.
The design, fabrication, integration, and startup of the Erha FPSO was a global undertaking, with engineering performed primarily in France, India, and Nigeria; hull fabrication in Korea; and topside fabrication in Singapore, Malaysia, and Nigeria. The hull and topside were integrated in Singapore, and the FPSO was towed to offshore Nigeria for installation. This work was carried out under a single prime contractor, Saipem S.A., and its in-country affiliate, Saipem Contracting Nigeria Ltd. (SCNL) and included key design and execution interfaces with the Erha tiebacks and subsea-system prime contractors.

Facilities Description
The Erha FPSO (Fig. 1) is a barge-shaped, new-build monohull with all of the processing equipment on its top deck. It has a 2.2-million-bbl oil-storage capacity. Processed oil is offloaded to export tankers by the CALM buoy offloading system. The FPSO also has the capability to offload crude to tandem moored export tankers in a "bow-to-bow" configuration in the event that the offshore loading system is not available.
Wireline Pressure Measurements Improve Reservoir Characterization in Tight Gas Formation
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 109565, "A Case Study: Using Wireline Pressure Measurements To Improve Reservoir Characterization in Tight-Formation Gas¡ªWamsutter Field, Wyoming," by R.A. Schrooten, SPE, BP America; E.C. Boratko, SPE, H. Singh, SPE, and D.L. Hallford, SPE, Schlumberger; and J. McKay, BP America, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11-14 November.
Improving recovery in tight gas reservoirs typically requires infill-drilling programs. Characterization of reservoir-pressure depletion and sand-body continuity is fundamental to determining the economic viability of these projects. In tight gas reservoirs, new wireline tools that use precise pretest mechanisms can achieve the required data-acquisition objectives. However, wellbore conditions and data-acquisition procedures can greatly influence the quality and limits of data application.

Introduction
The Wamsutter field is a large, continuous tight-formation gas accumulation in the Washakie and Red Desert basins of the Greater Green River basin in southwest Wyoming. Discovered in the 1950s, it encompasses 1,700 sq miles and is one of the largest tight gas resources in North America. The field area has produced 2 Tcf from more than 2,000 wells since discovery in the late 1950s. The primary productive interval is the Almond formation of the Mesaverde group, comprising shallow marine sandstones deposited along the western margin of the Cretaceous seaway.
Improving recovery in tight gas reservoirs leads to tight well spacing, driven by reservoir connectivity, permeability, well costs, and gas prices. These fields typically go through multiple rounds of downspacing on the basis of development pace, well-performance maturation, increased reservoir-characterization information, and technology advancements. This process can lead to less-than-optimal spacing and completions.
An elusive challenge with tight-formation spacing studies has been to gather fit-for-purpose pressure data in these reservoirs. A typical Wamsutter well will encounter a 500-ft gross (100-ft net) interval in the Almond, comprising 10 to 20 sands each averaging less than 10 ft in thickness. The result is a high level of heterogeneity. The historic inability to adequately or accurately sample individual-sand pressures throughout the productive interval while infill-developing mature producing areas has relegated historic drainage and recovery characterizations to overly simplistic and overly homogeneous tank-type material-balance solutions. The lack of dynamic layer-by-layer depletion detail can lead to erroneous modeling or poorly constrained recovery predictions and equally flawed claims for well-spacing requirements.
What Will the Oil and Gas Industry Do This Time?
Authors: Holditch Stephen A. 
Published: February 2015

Guest editorial
From 1972 to 1982, the enrollment in petroleum engineering departments in the United States increased substantially. We are currently seeing a similar increase in enrollment in petroleum engineering schools. Fig. 1 shows the total US petroleum engineering enrollment from 1972 to 2009. The enrollment peaked at just over 12,000 total students. In 1972, there were 1,362 undergraduate students in US universities. By 1983, the number had increased to 11,014. By comparison, in 2003, there were 1,673 undergraduates, and by the start of the fall semester 2008, the number of undergraduates had increased to 4,199. As can be seen in Fig. 2, the growth trend in undergraduate student enrollment from 2003 to 2009 is similar to the growth trend from 1972 to 1978.
The Department of Petroleum Engineering at Texas A&M University in 2003 only graduated 35 students with BS degrees and 46 students with MS or PhD degrees. In 2004, the oil and gas industry asked all the departments of petroleum engineering in the US to increase enrollment and graduates, and the universities have responded to that request. This year, the Department of Petroleum Engineering at Texas A&M will graduate more than 100 students with BS degrees and more than 50 with graduate degrees.
Now the oil and gas industry must do its part and hire these graduate engineers. Such a request seems almost silly if one has been reading all the articles during the past few years about the shortage of engineers in the oil and gas industry, and attending all the panel sessions at all the meetings to discuss what the industry needs to do to fill the age gap that exists in most companies, especially US domestic companies that do not hire an international work force. However, with the current economic downturn and the unexplainable increase and decrease in oil prices from a high of USD 147/bbl to the current price of around USD 40/bbl, some students are starting to ask questions about their job prospects and their career choice in general.
Techbits: Slimhole Sand Control Evaluated at Malaysian Workshop
Authors: JPT staff _ 
Published: February 2015

Techbits
Remedial and slimhole sand control completions took center stage at a recent SPE Advanced Technology Workshop (ATW) held in November 2008 in Penang, Malaysia. Titled "Chasing Lost Reserves with Remedial and Slimhole Sand Control," the ATW reviewed methods for maximizing recovery of reserves in place by using economical through-tubing and slim-hole sand control technologies.
Over the course of three days, 64 participants from 25 different organizations and 11 countries reviewed state-of-the-art sand control technology and recent technical advancements. They also benefited from the experience of other operators who shared case histories and established a network for information exchange with fellow participants.
Cochairpersons Michael Bailey (Drilling and Completions Engineer with ConocoPhillips) and Raymond Tibbles (Stimulation and Sand Control Adviser, Middle East and Africa, for Schlumberger), opened the ATW with an overview of the goals and objectives for the workshop. They encouraged all attendees to participate with any lessons learned from sand control technologies that they had applied.
This was followed by the keynote address by Haji Kamaludin Bungsu, Asset Manager (Western Asset), Brunei Shell Petroleum (BSP) Company. Bungsu's speech provided an overview of the reserves recovery challenges facing operators in the region, with particular emphasis on the cost and time required to develop new assets and the need to recover the maximum amount of reserves from existing developments. He then discussed the problems associated with brownfield sand production, either due to failure of primary sand control or late-time formation failure when no sand control was installed. He finished with a list of some of the options BSP was exploring to address these issues, while reiterating the need for more and better tools for later term sand remediation and better working relationships between operators and service companies.
The first technical session was a discussion on the economic drivers for remedial sand control and the need to think about a well's entire productive life during the initial design phases. An overriding message was how initial completion choices drive the decisions for the rest of the well life and how some simple changes can produce a significant impact. One example detailed how increasing the size of slimhole completions from 3.5 to 4.5 in. can create many more remedial possibilities at lower risk.
The next two sessions reviewed the various techniques available for through-tubing and slimhole sand control. Discussion topics ranged from resin consolidation and screenless fracture packs to through-tubing gravel packs, vent screens, and expanding tubular applications. In addition to discussing the techniques themselves, much time was devoted to weighing the risks associated with these techniques and their impact on productivity.
The Oil Curtain and the Evolution of National Oil Companies
Authors: Rasheed Wajid 
Published: February 2015

Management
Sketch out the global landscape of reserves and production and its most salient features would be the growing appetite for oil and gas and the drive for reserves replacement from frontiers and mature fields. In the background lie the cycles of "feast or famine" and the long lead times that govern investment and returns. Tantalizingly hidden away is the essence of the industry—petroleum reserves.
The Oil Curtain neatly symbolizes resource sovereignty and separates the hydrocarbon "haves" from the "have nots." It has led to the major part of proved global oil reserves being booked by national or state oil companies (NOCs). To illustrate the change of ownership, in 1971 NOCs held 30% of total global reserves while international oil companies (IOCs) held 70%. Today NOCs have increased their share to 93% while IOCs hold 7%. What caused such a dramatic reversal in fortune?
Since the early 1900s the importance of oil in financial, political, and strategic matters has been bubbling up to the surface. Eventually, this led to a pressing need for producing states to control oil. Mexico was first to "shut" the oil curtain by nationalizing its oil assets and forming the wholly state-owned Pemex (Petróleos Mexicanos) in 1938. By 1960, resource sovereignty had fully matured into a global force and the Central Bank of Oil—the Organization of the Petroleum Exporting Countries (OPEC)—was created.
OPEC's central message was clear: oil was too important to leave in the hands of foreigners. It would seek to regulate "oil rents" and end arbitrary payments from foreign oil companies. OPEC's thinking was shaped threefold. First, deals favored foreign oil companies and foreign governments, not producing states. Foreign oil companies also controlled an outward flow of profits, which were often the greater part of producing countries’ gross domestic product. Generally, beneficiaries were foreign governments either directly through shareholder dividends or indirectly through taxes. Secondly, foreigners took vital political decisions affecting the sovereignty of producing countries. Oil production, foreign exchange earnings through oil sales, and ultimately, national debt were being dictated by foreign oil companies. Lastly, the military and naval campaigns of the Second World War combined with the utility of oil in general transportation left no doubt that oil was a primary strategic asset.
Nexen's Buzzard to Fly with Fourth Platform
Authors: Sheehan John 
Published: February 2015

Canada's Nexen is pushing ahead with the next phase in the development of its Buzzard field in the UK sector of the North Sea, with a plan to install a new hydrogen sulfide (H2S) treatment platform due to get into full swing this year. The new "crude-sweetening" platform will be installed as part of the Buzzard Enhancement Project on the 600 million bbl field, which straddles two licenses—P.986 (Blocks 19/10 and 20/6) and P.928(S) (Blocks 19/5a and 20/1S).
Buzzard is the largest discovery on the UK Continental Shelf (UKCS) in more than a decade and has been developed with three bridge-linked platforms, soon to become four when the new platform is fully installed in 2010. The field is operated by Nexen with 43.2% interest, and partners include Petro-Canada 29.9%, BG Group 21.7%, Dyas UK 2.6%, and Oranje-Nassau 2.6%.
The field was discovered in the Outer Moray Firth in May 2001 with the 20/6-3 exploration well, which hit a 400 ft oil column and was flow tested at 6,547 BOPD of 32ºAPI crude oil. Construction work on the development was completed in 2006 and first oil flowed in January 2007.
Peter Addy, Nexen's Project Director for Buzzard, said that production is currently running at 210,000–215,000 BOPD and 30 MMcf/D of gas through 14 production wells with a further 12 producers planned. Reservoir pressure is currently sustained by water injection. The John Shaw semisubmersible and the Transocean Galaxy III jackup rigs have carried out the development drilling program on the wells that feed into the Buzzard processing complex.
The production platform receives multiphase reservoir fluids through the bridge-linked wellhead platform and processes them to separate crude oil, gas, and water.
Oil is then exported through an 18-in., 30-km pipeline, tieing-in subsea to the Forties Pipeline System. From there it is sent on through the onshore section of the pipeline system to Kinneil, crude oil stabilization terminal on the Firth of Forth in Scotland, for further processing and export by tanker. Gas is exported by a 10-in., 29-km line to the Captain T point on the UK Frigg gas pipeline.
Technology Focus: Offshore Facilities (February 2009)
Authors: Valenchon Claude 
Published: February 2015

Technology Focus
After many years of development work, as well as many unsuccessful attempts, the first liquefied-natural-gas (LNG) floating production, storage, and offloading (FPSO) initiative was launched in 1976 by Linde, Technigaz, et al. under the name Consortium 76—offshore LNG now is a reality. The first LNG receiving terminal installed on a gravity-based structure offshore Rovigo, Italy, will be commissioned soon. The first floating storage and regasification unit (FSRU) permanently moored in open sea offshore Livorno, Italy, is under construction, and several LNG carriers equipped with regasification facilities are able to deliver gas at several offshore ports in North America.
Offshore liquefaction also seems close to materialization, with several participants (including oil companies; engineering, procurement, and construction contractors; ship owners; and others) developing LNG FPSO solutions for stand-alone gas fields or for associated-gas developments.
Two main ways to approach these facilities seem to be pursued by the various participants. The "big way" is followed mainly by major oil companies: It aims at developing large-capacity liquefaction units (3×106 tonnes/a and larger) by use of processes generally derived from latest-generation onshore liquefaction cycles. A second trend, which could be called the "small way," targets smaller capacities, by use of less-efficient processes often based on nitrogen cycles, but having better suitability for use on board a floater.
While the latter probably has a wider range of potential application cases and would ease topside layout and safety concerns for a lower overall capital expenditure, the former will provide higher liquefaction efficiency and will target economies of scale. In turn, it might be applicable to only a limited number of relatively large gasfield developments.
Today, both approaches have equal chances to open the way for offshore floating liquefaction, but, certainly, both will need to rely on experienced companies that can gather and leverage experience in offshore regasification gained from the first FSRUs, combined with experience in large oil FPSOs and in onshore liquefaction.
All the industry needs now is a good gas field!
Offshore Facilities additional reading available at OnePetro: www.onepetro.org
OTC 19429 • "A Coupled FE-SPH Approach for Simulation of Structural Response to Extreme Wave and Green Water Loading" by J.C. Campbell, Cranfield University, et al.
OTC 19239 • "Innovative Pipe System for Offshore LNG Transfer" by Ing. C. Frohne, Nexans Deutschland Industries, et al.
OTC 19315 • "Deepwater Moorings With High-Stiffness Polyester and PEN-Fiber Ropes" by P. Davies, IFREMER Brest, et al.