bluuebunny/crossref_metadata_2025 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.
Pressure-Transient Testing and Production Logging To Monitor Performance of the Mars Deepwater Field
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 115591, "Case- History Review of the Application of Pressure-Transient Testing and Production Logging in Monitoring the Performance of the Mars Deepwater Gulf of Mexico Field," by Jeffrey Weiland, Shell, and Mehdi Azari, SPE, S. Suparman, SPE, Phil Fox, SPE, and Daniel Dorffer, SPE, Halliburton, prepared for the 2008 SPE Annual Technical Conference and Ex hibition, Denver, 21-24 September. The paper has not been peer reviewed.

Proper producing-well characterization is necessary for asset management. Whether the reservoir has partial aquifer influx or is waterflooded, the flow profile of produced/injected water and the reservoir pressure, permeability, fluid saturations, and formation compaction are useful to evaluate the overall sweep efficiency properly. This information is more crucial in a field with multilayered reservoirs having different permeabilities, pressures, and structures. Multirate/multi-zone (MRMZ) production logging and pressure-transient testing help obtain necessary information.

Introduction

Many of the Gulf of Mexico Mars field wells produce from multiple reservoir layers, making MRMZ production-logging and well-testing surveys valuable methods to estimate the layer flow rates, pressures, permeabilities, and skin factors and the distance to and type of boundaries. A surveillance logging program has been conducted since 2004, with initial baseline surveys to monitor and optimize production performance and to track waterflood progress. This approach allows reservoir characterization without requiring zonal isolation. It also helps to evaluate where the waterflood has influenced pressure maintenance.

Monitoring the waterflood with cased-hole logs is critical to improving the performance and increasing the overall recovery. The ability to acquire carbon/oxygen data for monitoring sea-water injection and sigma data for reservoir-fluid changes, combined with MRMZ production logging and testing, is essential in reducing unnecessary risks of well intervention.

Objectives

Production logging in the Mars field has facilitated reservoir management by identifying and reducing excessive water production. Production logging was designed to obtain one or more of the following reservoir and wellbore objectives.Characterize production or injection along the productive intervals of the wells.Determine the source of the excessive water production for further remedial work.Determine crossflow between the layers at shut-in and at low flow-rate conditions.Verify if all perforations are effective.Determine the productivity index for each layer and for the entire perforated interval.Evaluate individual-layer pressures and flow rates for each fluid phase.Check for bypassed hydrocarbon zones with pulsed-neutron and carbon/oxygen logging.Monitor stimulation or completion effectiveness.Confirm the length and sizes of downhole tubulars used.
The Quadruple Bottom Line (March 2004)
Authors: Baker Kate H.
Published: February 2015

President's column - No abstract available.
Comments (March 2004)
Authors: Donnelly John
Published: February 2015

Editor's column - No abstract available.
New Environmentally Friendly Frac Fluid Developed for Offshore Applications
Authors: JPT staff _
Published: February 2015

Technology Update - No abstract available.
After-Closure Analysis to Improve Hydraulic-Fracturing Designs in Algeria's In-Adaoui Gas Field
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 80936, "Use of After-Closure Analysis to Improve Hydraulic-Fracturing Designs: Application in Algeria's In- Adaoui Gas Field," by S. Benelkadi, R. Belhaouas, and M. Sahar, Sonatrach Inc., prepared for the 2003 SPE Production and Operations Symposium, Oklahoma City, Oklahoma, 22-25 March.
Evaluating Well Performance and Completion Effectiveness in Low-Permeability Gas Wells
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 84214, "Evaluating Well Performance and Completion Effectiveness in Hydraulically Fractured Low-Permeability Gas Wells," by David D. Cramer, SPE, BJ Services Co., prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
Overview: Production Operations (March 2004)
Authors: Rogers John D.
Published: February 2015

Overview - No abstract available.
Instrumented Oil Field and Emerging Measurement Technologies
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 15075, "The Instrumented Oil Field and Emerging Measurement Technologies," by David H. Johnston, SPE, ExxonMobil Exploration Co., J. Jane Shyeh, SPE, ExxonMobil Upstream Research Co., William N. Barkhouse, SPE, ExxonMobil Exploration Co., and John V. Young, Exxon- Mobil Upstream Research Co., originally presented at the 2003 Offshore Technology Conference, Houston, 5-8 May.
Reliable On-Site H2S and CO2 Concentrations for Anticorrosion Measures in Gas Wells
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 81495, "Getting Reliable On- Site H2S and CO2 Concentrations for Anticorrosion Measures in Gas Wells," by J.M. Williams, SPE, Saudi Aramco, prepared for the 2003 SPE Middle East Oil Show, Bahrain, 9-12 June.
Hydrate-Control and -Remediation Best Practices in Deepwater Oil Developments
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 15255, "Hydrate-Control and -Remediation Best Practices in Deepwater Oil Developments," by Steven Cochran, SPE, INTEC Engineering, originally presented at the 2003 Offshore Technology Conference, Houston, 5-8 May.
Underbalanced Drilling With Casing in South Texas
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 84173, "Underbalanced Drilling With Casing Evolution in the South Texas Vicksburg," by Doug Gordon, SPE, Rich Billa, SPE, and Mike Weissman, SPE, Shell E&P Co., and Fu Hou, SPE, Shell Intl. E&P Inc., prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
Q&A with Mike O'Brien
Authors: O'Brien Mike , Donnelly John
Published: February 2015

What is the government doing to attract interest in U.K. oil and gas production?

We are fully committed to extracting every last drop of economic oil and gas from the U.K. Continental Shelf. To do this, we need to make sure we have the players and licensing system to match the opportunities and the right business and regulatory environment to give stability and certainty for investment. To this end we are positively and vigorously pursuing a range of initiatives with the oil and gas industry, including promoting the opportunities to attract new players, modifying the licensing system, freeing up fallow acreage and discoveries, and ensuring that there is fair and reasonable access to infrastructure. On the technical side, we want to ensure that the wealth of geological and production data that has been gathered over the years is available to those wanting to invest.

What have been the accomplishments of Pilot, the joint government/industry initiative formed in 2000 to secure long-term oil and natural gas production from the U.K. Continental Shelf?

Pilot is very important to the government. We see it as a great example of industry and government working together in partnership. It has achieved many good things, not least of which is the ability for us to sit down together with the industry, debate, and move forward on key issues effectively. We want to see Pilot continue to succeed and we will continue to do all we can to achieve that success. Of the current key Pilot initiatives, we have seen a good deal of movement recently on infrastructure access.

Potential investors should not be deterred from examining the potential of the North Sea because they think it would be too time-consuming, costly, or difficult to acquire acreage or utilize existing infrastructure. The industry has been fully engaged and has worked hard to construct a process that will ensure third-party access to infrastructure on fair and reasonable terms. The system to achieve this is now being implemented and will further enhance the commercial climate here.
Erosion by Sand and Ceramic Proppants During Slurry Injection and Proppant Flowback
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90604, "Erosion by Proppant: A Comparison of the Erosivity of Sand and Ceramic Proppants During Slurry Injection and Flowback of Proppant," by M.C. Vincent, SPE, Carbo Ceramics Inc.; H.B. Miller, U. of Arizona; D. Milton-Tayler, SPE, FracTech Ltd.; and P.B. Kaufman, SPE, Carbo Ceramics Inc., prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.

During fracture-stimulation treatments, particle-laden slurries may damage pumping equipment and have been shown to erode perforation tunnels. During subsequent flowback operations, minor to severe erosion of surface equipment may be observed if formation sand and/or proppants are produced. This paper compares the erosivity of sand-based and ceramic proppants. The erosion mechanisms are examined, and theoretical and laboratory measurements are in agreement that low-density ceramic proppants, because of roundness and sphericity, are less erosive than more-angular sand products.

Introduction

Impingement tests designed to simulate flowback conditions demonstrated that use of a spherical lightweight ceramic (LWC) may reduce wellhead or other impingement-surface erosion by up to 95% compared with an angular sand. Additional studies with intentionally crushed proppant (to increase angularity) demonstrate that proppant shape is a dominant factor in controlling erosion. Surprisingly, flowback testing has shown that resin coatings applied to proppant can increase erosion 15-fold. Erosivity and abrasiveness of all proppant types were shown to increase with prop-pant damage. Erosion in chokes was found to be three times greater with sand than with LWC. Several laboratory studies have demonstrated that spherical proppants are less likely to flow back from the fracture than more-angular products.
Optimizing Horizontal Completions in the Barnett Shale With Microseismic Fracture Mapping
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90051, "Optimizing Horizontal-Completion Techniques in the Barnett Shale Using Microseismic Fracture Mapping," by M.K. Fisher, SPE, Pinnacle Technologies; J.R. Heinze, SPE, and C.D. Harris, SPE, Devon Energy Corp.; B.M. Davidson, SPE, C.A. Wright, and K.P. Dunn, Pinnacle Technologies, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.

The Barnett shale of north Texas is an ultralow-permeability reservoir that must be fracture stimulated to obtain commercial production. Techniques to optimize hydraulic-fracturing effectiveness have evolved over the past decade. In 2002, the Newark East field produced 202 Bcf, the seventh largest gas producer in the U.S. This pilot study compared production from the first 23 horizontal wells in a “core” area of the Fort Worth basin with vertical wells in the same area. Drilling and completion strategies, fracture-network areas, and fracture effectiveness were compared with the standard procedures used in vertical Barnett wells.

Introduction

The commercial success of Barnett shale development programs is attributed to a change in stimulation techniques in 1998. Previously, most Barnett shale wells were completed with massive hydraulic-fracture treatments that used crosslinked-gelled fluids, some carrying more than 1 million lbm of proppant. Because of the extremely low permeability of the Barnett, its inability to efficiently clean up fracture damage from gels, and the high cost of massive hydraulic stimulations, most Barnett treatments did not provide an adequate investment return. In 1998, Devon Energy experimented with an old fracturing technique that was regaining acceptance at the time in east Texas. The technique was light sand fracturing, or “waterfracs.” In the Barnett shale, this technique provided a much larger surface area of contact with the reservoir and minimized fracture-face damage, resulting in improved productivity.

Even with the success with light sand-fracturing treatments, not every area of the Barnett proved as successful as the core area in Wise and Denton counties. As shown in Fig. 1, the Barnett shale covers a large area, from the Fort Worth basin past the Permian Basin of west Texas, into New Mexico, but the quality and quantity of Barnett pay varies substantially from the traditional core area to the newer plays on the fringes. Successful development in the newer areas will likely require additional changes in completion techniques, and several new strategies are being tested in both core and fringe areas of the Barnett shale.
Stand Tall and Speak Up: Work and Your Other Life - Navigating the Course
Authors: Sprunt Eve S.
Published: February 2015

My favorite adage about work/life balance is not the oft-quoted saying, "No one on their deathbed ever wished they'd spent more time at the office." Instead, I prefer the advice to "write your own obituary."

Although the first is a good warning, it doesn't provide much guidance. In contrast, the second supplies a technique to help you plan your life even at an advanced age. Alfred Nobel made a fortune by inventing and manufacturing dynamite. In 1888, when his brother Ludvig died, a newspaper misattributed the work of Alfred to his brother and printed the headline, "The Merchant of Death is Dead!" Disgusted by the obituary of himself, Alfred Nobel decided to use his wealth to alter his legacy. When he died 8 years later, he provided funds for awards for people whose work was of benefit to humanity and in doing so successfully turned around society's assessment of him. Today, almost no one associates Nobel Prizes with death from the use of dynamite.

The exercise of writing your own obituary and thinking about what you want to accomplish is a good way to clarify your priorities. Then, you can work the inverse problem to identify the steps you must take. As Alfred Nobel's story illustrates, even if you are in the sunset of your life, it is not too late to ask yourself what you want to accomplish with the remaining time you have.

Meshing career planning with work/life balance issues is challenging, because we each have different dreams and priorities. One person's perfect job is another person's worst nightmare. Also, since our family situations and goals change with time, the ideal job at one point in our life may be totally unacceptable at another time. People are not mind readers, so we must not expect someone else to intuit what we want. We must be willing to tell them what we want or to figure out for ourselves how to execute an alternative plan. We must also recognize that the choices we make may cost us promotions or rapid advancement. For me, this is the central premise of being responsible for your own career.

Experience is cumulative. If, for work/life balance reasons, we choose to seek positions that do not provide the opportunities to develop certain skills, we must recognize the consequences of our actions. Later, it will be difficult to secure a job that has those skills as a prerequisite, unless we can convince people that we have equivalent competencies. Alternatively, we may be willing to take on the responsibilities of a position, but not be selected for a role that provides the experience we desire. In either case, to get past the roadblock we need to take independent action.
Technology Update: Manufacturing Approach to Fracturing Limits Environmental Impact
Authors: JPT staff _
Published: February 2015

In the Rocky Mountains in Wyoming, a manufacturing approach is being developed to enable fracture stimulation of hundreds of gas wells from one semipermanent location that can operate around the clock. This development is in response to the area's unconventional gas fields that offer unique environmental, social, and operational challenges. Fig. 1 shows this concept, called FracFactory service, in schematic form.

Fig. 2 illustrates that the FracFactory service concept is appreciably different from the conventional layout of a frac spread. For every well treated, the conventional frac-equipment spread is transported from a logistical base directly to the location, set up for operation, broken down after the stimulation job is completed, and transported back to the base/satellite storage facility. The process is repeated for every well treated, with potentially significant impact to the environment, resources, and required man-hours. This is the current practice across the industry.

To help reduce the environmental footprint, many wells can be drilled in clusters from a single location. Surface piping can be installed to provide a conduit for the frac fluid from the FracFactory service facility to the well cluster for placement downhole. An efficient system of manifolding at each well cluster completes the connection from the pressure pumps to the appropriate wellhead. Fig. 3 shows the concept in greater detail—supplies, crew quarters, pumping and blending gear, and water reclamation equipment within a single footprint. High-pressure pumping is housed nearby in an enclosure designed to reduce the noise level for the crew and the surrounding local environment.

Opportunities Wrapped in Challenges

Recent authorizations to drill for gas on Bureau of Land Management (BLM) lands has handed E&P companies and service companies an opportunity wrapped tightly in a number of challenges. Companies must:Operate with a small footprint on the mountains and prairie valleys of Wyoming.Avoid lowering the water table to supply fluids required in fracture stimulation of production from unconventional (tight) reservoirs.Avoid creating excessive traffic on local roads and across lands that are home to numerous game animals.Protect aquifers from contamination.Provide efficient well-stimulation operations with minimal non-productive time caused by the logistics concerned.

The Rockies are believed to hold enough gas to heat and cool 70 million homes for nearly 50 years, but reserves are located in hard-to-produce reservoirs. Because the U.S. government controls so much of the land in this part of the country, oil and gas producers have flooded BLM with applications for drill permits. One major operating company plans to spend about U.S. $2.2 billion in the next 15 years to drill 2,000 wells in Wyoming's Wamsutter field. In fiscal 2004, BLM approved 5,747 drilling applications to drill on public lands in Wyoming, Colorado, New Mexico, Utah, and Montana, up four-fold from the industry slump in 1999.
Overview: Hydraulic Fracturing (March 2006)
Authors: Chipperfield Simon
Published: February 2015

Innovation can come from surprising places.

Henry Bessemer commented, after developing the modern steel-making process: "I had an immense advantage over many others dealing with the problem inasmuch as I had no fixed ideas derived from long-established practice to control and bias my mind, and did not suffer from the general belief that whatever is, is right."

The key to Bessemer's success was his unique and unencumbered way of thinking. In hydraulic fracturing, many new technologies have been developed in a similar manner, namely by introducing new ways of thinking, often developed in different areas of our industry.

Microseismics, a technology more closely associated with geophysics, now is used by engineers to optimize hydraulic fracturing, and, in some reservoirs, it reveals a more complicated geometry than many people previously predicted. The challenges now for engineers are to better understand what drives this complexity and to further optimize stimulation treatments.

Fracture stimulation has recently learned from both traditional reservoir engineering and classical heat-transfer theory to develop after-closure analysis and other diagnostic-injection approaches. These methods enable more accurate reservoir characterization.

Hydraulic fracturing also has merged with conventional sand control. This application of hydraulic fracturing (termed frac packing) has extended into more-challenging environments such as deep water, increasingly less consolidated reservoirs, and areas where cost minimization is critical (e.g., the development of screenless sand control).

I anticipate that the trend of sharing ideas between disciplines will continue into the future, blurring the boundaries between fracture stimulation and other sciences.

The next generation of hydraulic fracturing will challenge the existing paradigm, in much the same way as the above technologies have. It is crucial that we continue to challenge the accepted wisdom and to encourage and test ideas that some might label "crazy."

As Albert Einstein said, "If at first the idea is not absurd, then there is no hope for it."

Hydraulic Fracturing additional reading available at the SPE eLibrary: www.spe.org

SPE 95568 "Comparison of Single- and Dual-Array Microseismic Mapping Techniques in the Barnett Shale," by N.R. Warpinski, SPE, Pinnacle Technologies Inc., et al.

SPE 93419 "After-Closure Analysis To Determine Formation Permeability, Reservoir Pressure, and Residual Fracture Properties," by M.Y. Soliman, SPE, Halliburton, et al.

SPE 97994 "Application of Microseismic-Imaging Technology in the Appalachian Basin Upper Devonian Stimulation" by J. Fontaine, SPE, Universal Well Services, et al.

SPE 96080 "Developing Calibrated Fracture-Growth Models for Various Formations and Regions Across the United States" by L. Weijers, SPE, Pinnacle Technologies Inc. et al.