bluuebunny/crossref_metadata_2025 huggingface dataset:
Technology Focus: Well Stimulation (June 2008)
Authors: Hager Charles
Published: February 2015

Technology Focus

This feature highlights three papers that are examples of working smarter, better, or cheaper to help us be more competitive in an ever-growing world energy market. In 2004, oil and gas production was the leading supplier of energy generation with approximately 55% of the world market. Four key competitors made up more than 44%: coal, nuclear, hydroelectric, and bio-mass/waste. It would seem that new competitors continue to appear.

One major E&P company is touting its lead as the largest producer of magma-heated steam to drive power generators—enough to support millions of homes. The water captured after power generation is reinjected and reheated to temperatures as high as 570°F, completing a renewable-energy cycle. Then there is the latest liquid-sodium-cooled nuclear power plants, such as the "Toshiba 4S." Additionally, others are pushing solar, wind, bitumen, and now power plants that can switch between coal and natural gas. As the price of oil climbs, our competitors will catch up all the quicker to meet the world's growing energy needs.

Now is the time to raise the bar for defining well-stimulation success, not after our competitors have caught up. Is it possible that we spend too much time looking at future wells and not enough quantifying past results? Let us take the example of stimulating a four-fold increase in production, which generates a high economic return. If we determine that we could have achieved a six-fold increase with a greater return, or perhaps even a 20-fold increase by combining with a multistage-treated horizontal well, does this alter our idea of success?

It is time to take stimulation effectiveness to the next level, being measured and understood more reliably through integrated and detailed approaches. Success should be demonstrated through consistent engineered improvements. It is defining a greater understanding from previous stimulations that will allow us to realize more rapidly what is possible, thereby increasing our level of competition in a world market, one well at a time.

Well Stimulation additional reading available at the SPE eLibrary: www.spe.org

SPE 110707 • "Real-Time Diversion Quantification and Optimization Using DTS" by Gerard Glasbergen, SPE, Halliburton, et al.

SPE 111512 • "Innovative Water-Shutoff Solution Enhances Oil Recovery From a West Venezuela Sandstone Reservoir" by Goran Andersson, PetroBoscan, et al.
New HF-Acid System for a Heavy-Crude Brownfield With Fines Problems
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 112558, "Increasing Production in a Brownfield With Heavy Crude and Fines Problems by Application of New HF-Acid System: Case Histories," by Folorunso Afolabi, SPE, Austa Opusunju, SPE, and Jaspers Henri, SPE, Shell, and Cletus Onyekwere, SPE, Chris Onyekwere, SPE, and Davalos Juan, SPE, Weafri, prepared for the 2008 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 13–15 February. The paper has not been peer reviewed.

Minimizing fines migration and improving high-water-cut-well productivities with improved treatment-fluid designs, detailed candidate selection, and enhanced pumping methods yielded positive results in aged-field production enhancement. A slow-release-hydrogen retarded-hydrofluoric-acid (SRH-RHF) system was used on the basis of a detailed candidate selection, case-specific fluid design for high-water-cut wells, and mechanism of fines and clay migration and control methodology to acidize heavy- or medium-crude reservoirs.

Introduction

Improving productivity in these Niger delta brownfields that produce heavy crude and experience fines migration had been approached with little or no consideration to such challenges as water production. Many wells were treated with a conventional mud-acid system, either with or without a solvent-soak treatment. Clay-control agents are no longer used to stop fines problems because the additive had little effect. Wells with high water cut were treated only with solvent material, realizing minimal effect. Foam diversion often had inconsistent results. Other diverting techniques also proved unpredictable in this environment. A coating of heavy crude on the formation wall inhibited the reaction of the mud-acid system with the formation. An acid system or formulation that would maintain matrix acidizing was needed for well-productivity problems in the Niger delta.

In December 1996, an SRH-RHF sys-tem was used. Data indicated a consistent production increase with evidence of deep penetration into the damaged zone. Failures experienced with this sys-tem were traced to a shortage of well information for proper diagnosis and the need for a core-flow test in one field with three treatments resulting in no increase or a reduction in production.

In the past, acid stimulation was limited to wells with water cut less than 30%. In late 2001, an improvement was made in candidate selection, treatment design, foam diversion, and pumping method for high-water-cut wells and heavy-crude wells. The high-water-cut limit was increased to 60%. In 2005, a new SRH-RHF system was developed. Its application in nine wells with heavy or medium crude was successful.
Coiled-Tubing Underbalanced Drilling in the Lisburne Field, Alaska
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 108337, "Coiled-Tubing Underbalanced-Drilling Applications in the Lisburne Field, Alaska," by Mark Johnson, SPE, BP; Patrick Brand, SPE, Blade; Sam French, SPE and Greg Sarber, SPE, BP; Dave Hildreth, SPE, Orbis; Bob Harris, SPE, Baker Oil Tool; Pedro Rangel, SPE, Schlumberger; Udo Cassee, SPE, Nordic; and Jimmy Clark, ASRC, prepared for the 2007 IADC/SPE Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition, Galveston, Texas, 28–29 March. The paper has not been peer reviewed.

In 2005, BP Alaska began evaluating the application of underbalanced-drilling (UBD) technology as a method for drilling multilateral wells in the Lisburne field. The evaluation process was enacted as a response to slow rate of penetration (ROP) through the hard carbonate Wahoo formation; frequent total losses of drilling fluid when drilling conventionally; and poor understanding of the orientation, frequency, and effect of fractures on production.

Introduction

The Lisburne carbonate reservoir has approximately 2 billion bbl of original oil in place. The Wahoo formation, at a depth of approximately 8,900 ft true vertical depth (TVD), is tight, fairly thick (400 ft), and highly consolidated, with thin interbedded mudstone layers. Reservoir fluid is mainly oil with a gas cap covering a portion of the field. The gas contains approximately 60 ppm H2S and 12% CO2.

Previous drilling in the reservoir was overbalanced. Lisburne is a hard-rock carbonate with unconfined compressive strengths from 15,000 to 25,000 psi. Drilling problems include low ROP when drilling overbalanced and instability of the mudstone layers when exposed to water-based muds (WBMs). Production performance of the reservoir in general has been disappointing, with an oil recovery to date of only 8% because of low matrix permeability and excessive gas production. It is apparent that the formation is fractured and that intersection of effective fractures is critical to well performance. Wells that have intersected significant fractures have been among the better performers.

In a bid to intersect more of the fractures, BP Alaska had attempted through-tubing coiled-tubing (CT) sidetracking, placing single horizontal laterals in the carbonate sections. Production-performance delivery of these wells has been 50% successful, prompting consideration of other alternatives. One of the main alternatives considered was through-tubing CT-UBD sidetracks. The idea was to place multiple laterals from a single main wellbore within the carbonate sections, thus increasing exposure and avoiding the potentially unstable mudstones. The main motivation for UBD was to improve ROP and eliminate drilling problems associated with overbalanced operations.
CT-Failure Causes: A Decade of Experience
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 113676, "CT-Failure Monitoring: A Decade of Experience," by A.R. Crabtree, SPE, BJ Services, prepared for the 2008 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 1–2 April. The paper has not been peer reviewed.

The full-length paper reviews a decade of tracking coiled-tubing (CT) failures and their causes and sets the results against the perspective of the changing nature of the business over the same time period. Critical factors for reliable CT service-life performance are identified, and whether reliability is higher today than a decade ago is examined.

Introduction

Since the beginning of 1996, all early CT-string failures experienced in company operations have been examined to identify cause of failure. The results of these examinations are recorded in a database to enable historical tracking, so trends can be observed and appropriate policy or procedural changes made. The full-length paper presents data captured from 1997 through 2007. Early failures are those that are experienced before the safe working life of a CT string has been fully consumed. Very few strings are used until they reach their maximum-allowable safe working life, and, therefore, this database basically captures all string-failure data.

The database contains information on more than 250 failure investigations. During the same period, more than 2,200 CT strings were in service, performing approximately 60,000 jobs, using an average of 138 CT units, with both land and offshore operating locations.

Research into the low-cycle fatigue performance of CT conducted since the early 1990s has resulted in predictive algorithms and fatigue-management software. This, combined with improved string-manufacturing techniques, has all but eliminated most pure cyclic-strain-induced fatigue failures (i.e., fatigue not associated with secondary mechanisms such as corrosion).

Data Overview

Examination of all the data (Fig. 1) shows that the leading reasons for early failure are dominated by five main classifications: corrosion, mechanical damage, manufacturing flaws (or defects), operator error, and hydrogen sulfide (H2S) cracking. These groups account for approximately 94% of all failures.

Reviewing the overall data and superimposing the number of jobs per year (Fig. 2), it can be seen that the number of failures appears to be proportional to jobs performed. This would seem to indicate that the failure rate (jobs performed/number of failures) has not improved. However, this is not the case because the chart belies the underlying numbers. In fact, the failure rate from 2000 through 2007 improved 47%. The year 2003 was anomalous and is a result, in part, of an increase in the CT fleet in the later portion of 2002, leading to the addition of several new CT strings being used in 2003.
How High-Speed Telemetry Affects the Drilling Process
Authors: Wassermann Ingolf , Kaniappan Aravindh
Published: February 2015

Technology Update

Regardless of whether you look at consumer or industrial applications, whenever a technical breakthrough in available communication bandwidth is achieved, the affected environment and feasible applications change significantly. One recent example was the introduction of the digital subscriber line (DSL) to replace modems for Internet access.

With high-speed telemetry systems becoming economically viable in an increasing number of drilling applications, our industry is in a situation similar to that seen at the introduction of DSL. Following the parallel of Internet access via DSL vs. modem, the relevant questions are: How has high-speed telemetry changed the drilling process, and what further changes will we see in the near future?

This article first intends to explain why oilfield service companies continually strive for higher telemetry data rates. It then identifies and exemplifies fields of application for both available technologies—high-speed mud-pulse telemetry and wired drillstring telemetry—with two case histories. The conclusion provides an outlook on possible future opportunities and technological developments.

Rationale for Higher Telemetry Data Rates

Every breakthrough in drilling technology creates an increasing demand on telemetry speed, requiring new telemetry technologies to meet that demand. Consequently, the meaning of high-speed telemetry has changed and will continue to change over time.

The most recent major change in drilling technologies has been the rise of increasingly sophisticated measurement-while-drilling (MWD) and logging-while-drilling (LWD) services, e.g., drilling dynamics, formation-pressure testing, high-resolution resistivity and electrical images, and magnetic-resonance measurements.

MWD and LWD services reduce the necessity for wireline runs and increase the log quality at the same time because the formation is logged immediately after penetration. In contrast to wireline logging, MWD/LWD tools "see" the freshly cut formation rather than logging it after days of exposure to drilling mud, which results in formation deterioration. They also make downhole drilling-dynamics measurements available in real time, something that has previously been impossible.

In the past, one of the major challenges with MWD/LWD services was the ability to transmit all the data gathered downhole. The majority of measurements were written to memory onboard the downhole tool, and only a fraction of the collected data was transmitted in real time to surface. The data then was retrieved from memory after pulling the drillstring out of hole.
Techbits: Digital Oilfield Developments Addressed in Joint Workshop
Authors: Moon Ted
Published: February 2015

Techbits

More than 70 petroleum engineers and information technology (IT) professionals converged on Salvador, Brazil last October for the SPE/IBP Joint Workshop on the Digital Oilfield. The workshop's mission: to review the current status of the digital oilfield concept and to understand what remains to be done to allow the industry to meet the demands of the 21st century.

"The E&P industry has led the way in applying leading-edge computing and communications technology," said work-shop Cochair Roger Hite of the Business Fundamental Group. "Seismic processing and imaging, reservoir simulation, and many other areas have provided notable advances to our business. In the 21st century, the fast pace of technology development continues, this time with the goal of automating and optimizing operations in the oil field itself. There is a renaissance under way that promises to yield enormous gains."

The workshop was organized into sessions that surveyed key questions on how well the industry is doing in developing the digital oil field. A mixture of presentations and group working sessions were employed to cover each topic. The first session set the stage by asking "Where are we today?"

"We set out to cover the landscape and to gain a broad view of progress, rather than focus on one aspect," said Hite. "In my opening remarks I said that the concept of the digital oil field is rapidly developing into an important reality in our industry." He also stated that the conclusions drawn about the digital oil field should be framed by business issues, namely, the value gained from the decisions that can be made and implemented and by the efficiencies that can be gained by automation.

"Perhaps the key challenges facing the industry are designing infrastructures to facilitate work processes, integrating across disciplines, learning how to navigate the mountains of data now available, and preparing convincing business cases," Hite continued. These key issues were the subjects of the subsequent sessions.

Infrastructure

"Discussions of infrastructure have moved beyond ways to establish connectivity to concerns about how that connectivity should be designed to facilitate collaboration and to enable improved work processes," said Hite. This session addressed how effectively infrastructure plans fit business needs.
Global Possibilities of Future Methane and Hydrogen Economies
Authors: Aguilera Roberto F. , Aguilera Roberto
Published: February 2015

Management

Jules Verne, the father of science fiction, wrote several books using ideas that eventually became reality. Some examples include: From the Earth to the Moon in 1866, Twenty Thousand Leagues Under the Sea in 1870 where he envisions submarines, Robur the Conqueror in 1886 where he describes the precursor of helicopters, and The Mysterious Island in 1875 where he wrote:

Yes, my friends, I believe that water will one day be employed as fuel, that hydrogen and oxygen which constitute it, used singly or together, will furnish an inexhaustible source of heat and light, of an intensity of which coal is not capable.

Vaitheeswaran (2003) asks, "Could the man who forecast the development of such technological marvels as submarines, helicopters, and space travel have gotten energy right, too?" We believe that the answer is most likely positive.

Hydrogen accounts for approximately 75% of the universe's mass and is the most abundant of all elements. Stars are made mainly of hydrogen. However, hydrogen does not generally exist in a free state in Earth. Consequently, it has to be extracted from different materials including, for example, biomass, fossil fuels, and water. This means that it takes energy to free hydrogen for use, no matter how it is produced. As a result, hydrogen is not strictly an energy source but an energy carrier much in the same way as electricity.

At present, while society is deeply concerned about the environment, hydrogen might emerge as a white knight. There is evidence that, since 1850, the relative hydrogen consumption has been increasing steadily (Fig. 1). Research shows continuous decarbonization from 1850 to 1970. At this point, the hydrogen/carbon (H/C) ratio becomes approximately constant (in the order of 1.8). Hefner (2002) describes this history for the US as follows: "For more than 100 years, free markets and the ingenuity of humankind worked efficiently to decarbonize our energy systems…. It was only starting in the 1950s, when governments began to tinker with price controls and later, reacting to the ‘sky is falling’ cries of shortages by the energy industry, allocated fuels among sectors of consumers, that we once again began to recarbonize the energy system." The recarbonization period described by Hefner occurs between approximately 1970 and 2006. However, the Global Energy Market (GEM) model tends to show a slight improvement in the H/C ratio as we advance toward the year 2030. This suggests an increase in production of natural gas which, we anticipate, will pave the way to an "energy revolution that will transform an industry, change our lives, and maybe even save the planet" (Vaitheeswaran, 2003).
Design Challenges for Wax in a Fast-Track Deepwater Project
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 19160, "Design Challenges Due to Wax on a Fast- Track Deepwater Project," by Amir Alwazzan, SPE, and Mark Utgard, SPE, AMEC Paragon, and Dalmo Barros, Petrobras America, prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed.

Flow-assurance threats, such as hydrates, waxes, and asphaltenes, can be identified and controlled if oil and gas production and transportation systems are designed accordingly and proper operating procedures are implemented. Therefore, prevention of wax deposition is key for good subsea deepwater-system design. Wax deposition can form a blockage and impede flow, causing weeks of lost production and operating difficulties.

Introduction

Flow assurance in subsea systems is an issue in the design of deepwater-field developments. Flow-assurance efforts focus on preventing solid deposits from blocking or restricting the rate of flow from the well. The principal solids of concern are wax and hydrates. For a given reservoir fluid, these solids precipitate at certain combinations of pressure and temperature. Precipitated solids often are carried downstream, slurried in the fluid, but precipitated solids also can deposit on the walls of the production equipment, which ultimately causes high pressure drops, plugging, and flow stoppage. Control of this deposition by prevention and/or mitigation is the essence of flow assurance.

Wax in hydrocarbons is primarily paraffin, which is a white, odorless, tasteless, chemically inert compound composed of saturated hydrocarbons. The linear paraffins are easily measured by high-temperature gas chromatograph (HTGC).

Two critical issues require special attention: gel formation (precipitation) and deposition. A hydrocarbon gel forms when wax precipitates from the oil and forms a 3D structure spanning the pipe. This condition does not occur while the fluid is flowing because the intermolecular structure is destroyed by shear forces as soon it is able to form. However, when the fluid stops flowing, wax particles will interact and join together, potentially forming a network resulting in a gel structure if enough wax comes out of solution. In a pipe, wax deposition results in flow restrictions. Slow buildup of wax layers in pipelines and flowlines is caused by the solidification of the paraffinic fractions on the cold inner surface of the pipe wall. Wax deposition is expected during steady-state operation in the flowline where the production-stream temperature is below the wax-appearance temperature (WAT). The deposition rate depends mainly on the fluid characteristics, flowing and pipe-wall temperatures, heat flux through the pipeline, and the shear stress at the wall.
Solving Excessive Water Production in a Long Horizontal Open Hole
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 113700, "Solving Excessive Water Production in a Prolific Long Horizontal Open Hole Drilled in a Naturally Fractured Carbonate Reservoir," by Stephen Lightford, SPE, Halliburton, and Enzo Pitoni, Giovanni Burrafato, and Claudia Porretta Serapiglia, Eni E&P, originally prepared for the 2008 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 1-2 April. The paper has not been peer reviewed.

A case history is presented of a successful operation to reduce excessive water production in a horizontal well drilled through a naturally fractured carbonate reservoir. Because the well was completed with a 940-m horizontal openhole section, there was no practical means of selectively isolating sections of the open hole. A treatment was performed using a sealant that would set up only in the presence of water. The full-length paper describes the philosophy behind the treatment design, the testing of the sealant, the placement procedure, and subsequent well performance.

Introduction

The case study is taken from a field in southern Italy that lies within a mountainous national-park area and is classified currently as the largest producing onshore field in continental Europe. Wells in the field are very-high-producing wells from a naturally fractured carbonate reservoir at approximately 3500 m true vertical depth (TVD). Permeability is difficult to predict because it is dependent on natural fracturing, which results in a wide range of production rates from individual wells. Because the field is in a national park, development is strictly controlled and wellsites are limited to fit in with the environment. Very strict governmental controls on the operations in the field help ensure that work is minimized to what is absolutely necessary. Planning to move a rig onto the wellsite normally is a long process to obtain the required authorizations and is particularly expensive because of the mountainous terrain. Rigless interventions and use of coiled tubing (CT) in the field have become widespread.

When a naturally flowing well suddenly starts producing excess water, and oil production is lost because the well is killed by increased hydrostatic pressure; there is an intense commercial driver to attempt to resolve the problem with a rigless intervention. This situation offers an opportunity to use newer techniques because the commercial benefits of a successful job make the amount of risk acceptable to an operator willing to resolve the problem. This scenario provides a rare opportunity to use untried methods, as was the case in the job described in the full-length paper.
SAGD Gas Lift Completions and Optimization: Surmont Field Study
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 117489, "SAGD Gas Lift Completions and Optimization: A Field Case Study at Surmont," by T.C. Handfield, T. Nations, SPE, and S.G. Noonan, SPE, ConocoPhillips, prepared for the 2008 SPE International Thermal Operations and Heavy Oil Symposium, Calgary, 20-23 October. The paper has not been peer reviewed.

Gas lift completions for steam-assisted-gravity-drainage (SAGD) producers are unique. Conventional gas lift valves and mandrels with a packer completion cannot be used because of the extreme temperatures of the downhole environment. Most lift gas enters the production stream downhole through open-ended tubing or nozzles, which, if not properly sized, can result in operational issues that negatively affect the overall lift efficiency. Data were collected and analyzed to determine the efficiency of two types of gas lift nozzles used in the completions. The method for optimizing SAGD gas lift systems is presented, and recommendations are made for future improvement.

Introduction

Surmont, an oil-sands project, is approximately 37 miles southeast of Fort McMurray in the Athabasca oil sands in Canada. The Surmont pilot began steam injection in 1997, comprising three SAGD-well pairs that use a variety of artificial-lift methods. These wells were tested to determine the preferred method of artificial lift for the first commercial phase.

Main steam injection was initiated in mid-2007, and conversion to full SAGD production followed in late 2007. Phase 1A comprises 20 well pairs in which all the producers were completed to produce by use of gas lift for the initial life of the well. Phases 1A, 1B, and 1C have a capacity of 25,000 B/D and are expected to reach peak production in 2012. A second phase is slated for commercial startup before the middle of the next decade, which, upon completion and full ramp-up, is estimated to bring peak production from both phases to 100,000 B/D. Additional phases at Surmont are under study.

Historical Perspective

The Surmont gas lift experience began with trials in two of the three pilot wells. The completions consisted of a single production string varying in size from 3.5 to 5.5 in. with a 1-in. coiled tubing (CT) run concentrically for gas lift and landed at the heel of the well. The bottom 2 m of the gas lift string was constructed similar to a perforated stinger with ten 11-mm orifices. These gas lifted wells operated with reservoir pressure as low as 334 psi, producing fluid rates between 1,047 and 3,352 B/D, with gas lift rates ranging from 211 to 339 Mscf/D for a total combined operating time between the two wells of 35 months.

The conclusion from testing at the pilot was that gas lift at the higher reservoir pressures was effective. However, before making additional designs and sensitivity studies, the gas lift assemblies were removed to allow for testing and validation of other forms of artificial lift for Surmont SAGD.
Ultralightweight Proppants Possess the Ability To Alter Fracturing Techniques
Authors: JPT staff _
Published: February 2015

This article contains highlights of paper SPE 84309, "Ultralightweight-Proppant Development Yields Exciting New Opportunities in Hydraulic Fracturing," by William D. Wood, Harold D. Brannon, Allan R. Rickards, and Chris Stephenson, BJ Services Co., prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
OTC 2004 Review
Authors: Denney Dennis , Langley Diane , Donnelly John
Published: February 2015

Conference review - No abstract available.
Overview: Well Stimulation (July 2004)
Authors: Dusterhoft Ron
Published: February 2015

Overview - No abstract available.
Acid Fracturing a Carbonate Reservoir
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 84130, "Acid Fracturing of a Gas Carbonate Reservoir: The Impact of Acid Type and Lithology on Fracture Half-Length and Width," by K.M. Bartko, SPE, H.A. Nasr-El-Din, SPE, Z. Rahim, SPE, and G.A. Al-Muntasheri, Saudi Aramco, prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
Casing-Running Challenges for Extended-Reach Wells
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 84447, "Casing-Running Challenges for Extended-Reach Wells," by Colin J. Mason, SPE, Jesse Lopez, Sigve Meling, and Robert Munger, SPE, BP plc, and Barry Fraser, Avanteq, prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5~8 October.
Overview: Health, Safety and Environment (July 2004)
Authors: Veil John
Published: February 2015

Overview - No abstract available.
Developing a Risk-Assessment and Situation-Response Program for Crisis Events
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 84056, "Developing a Risk- Assessment and Situation-Response Program for Crisis Events," by Vickie L. Butler Rindos, BJ Services Co., prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
Q&A with Andrew Gould
Authors: Gould Andrew , Donnelly John
Published: February 2015

As Chairman of the OE 2005 conference in Aberdeen, what issues do you think will attract particular interest at this year’s conference?

I think that general interest will be focused on how the industry can build and maintain production. There will obviously be a focus on the North Sea and the changes that will occur in the region as it becomes a mature basin. Therefore, I believe that there will be a lot of discussion about the technology needed to increase recovery factors. And there will undoubtedly be some spillover of the debate into where new production will come from and who is going to develop it. So I’m also expecting to hear discussion about the Middle East and Russia as well as on the roles of the national oil companies, the major integrated companies, and the independents.

One issue facing the North Sea region is how to manage a maturing production business. What new opportunities exist here for the service sector?

The main opportunity is to innovate to enhance recovery. North America and Canada already provide many opportunities for specialized services and specialized service companies. If you look at the Canadian market in particular, there are lots of companies that focus on one particular aspect of the business. So I think you will begin to see a service industry fragmented into specialists in particular aspects of managing and enhancing production from mature basins rather than a service industry organized around large development projects. Technology in the North Sea will become more and more fit for purpose if companies can justify the enhanced recovery process at a reasonable cost. So there will be many opportunities for both the big service companies as well as the smaller, local service operations.
OTC Sessions Confront Technical, Human Challenges Facing Industry
Authors: Donnelly John , Denney Dennis , Langley Diane
Published: February 2015

A healthy oil and gas industry fueled by high commodity prices provided the backdrop to a record-setting Offshore Technology Conference (OTC) in Houston.

The annual event posted a 20-year high in attendance at 51,320 and attracted more than 2,000 exhibiting companies (Fig. 1).

Amid the upbeat mood of an industry enjoying profitable times, speakers at the conference offered a clear-eyed view of the challenges confronting an industry that needs to produce more hydrocarbons to satisfy thirsty global demand. Peter J. Robertson, Vice Chairman of Chevron Corp., laid out those challenges in his keynote address at the OTC Awards Luncheon, including surging demand Robertson growth, geopolitical instability, increasingly complex projects, and consumer demand for cleaner fuels with minimal environmental impact. “To me the interesting part is that none of these items are particularly new, but the volume on all of them has been turned up and the combined effects of all of them operating in unison is putting a strain on our collective capabilities,” he said.

Those challenges will require huge financial investments. Robertson said that Chevron’s “big 5” upstream projects include three technically challenging deepwater developments in the Gulf of Mexico (GOM), Nigeria, and Angola; the expansion of the Tengiz field in Kazakhstan; and the Greater Gorgon project in Australia that includes two 5-million-ton liquefied natural gas (LNG) trains and a carbon sequestration project.

But the real test for the industry may not be in locating and developing hydrocarbons, but in finding and developing highly skilled technical people “to carry out all of this work,” he said. The average age of Chevron’s U.S. work force is 47, he said. “Just as more and more of our hydrocarbon resources are being sourced outside of the U.S. and Europe, in the future more and more of our people requirements will be sourced in other parts of the world where there are large numbers of talented, energetic, and interested young work forces—in Southeast Asia, the Former Soviet Union, Latin America, the Middle East, and in Africa,” he said.

At the awards banquet, 2005 Distinguished Achievement Awards were presented to J. Kim Vandiver, to Kerr-McGee Oil and Gas Corp., and to Technip. The award recognizes individuals, companies, and projects that have made outstanding contributions to the offshore industry. Vandiver, a professor of mechanical and ocean engineering at the Massachusetts Inst. of Technology, was honored for numerous technical breakthroughs in the dynamics of vortex-induced vibrations that have enhanced the design of structures to withstand high ocean currents. Kerr-McGee and Technip were cited for their successful global relationship that has pioneered and delivered three generations of spar floating production systems in the past decade.
A Modern Approach to E&P Asset Valuation, Development, and Decision Making
Authors: Evans Scot
Published: February 2015

The development of an oil and gas asset can be one of the most capital-intensive endeavors in the modern business world. The largest energy industry projects may require more than U.S. $15 billion in capital spending. While oil and gas assets normally have long economic lives, they have been characterized historically by low rates of return in comparison with endeavors in other industries. According to a recent report by Goldman Sachs, major oil company properties have an average life span of 21 years, but pay only 10% cash return on capital invested.

This level of performance can be attributed to two major challenges faced by nearly all recent E&P projects. First, most include substantial elements of risk and uncertainty, in terms both of commodity prices and estimates of subsurface hydrocarbon reserves and performance. Highly publicized write-downs of booked reserves illustrate the difficulties E&P companies face in this area.

The second major challenge is that conventional tools and techniques are unable to model all components of the production system simultaneously—from the subsurface upward through the wells, pipelines, and other surface facilities—across the entire productive life of an asset. Hence, engineers can create and evaluate no more than a handful of potential development scenarios, thus often resulting in suboptimal decisions. Traditionally, E&P companies resort to modeling each component of an asset—the subsurface, surface facilities, and economic outcomes—individually. At the end of this long, tedious process, they combine all the results, hoping they will represent the behavior of a fully integrated asset, which is rather questionable. Alternatively, they may simplify an integrated asset model to a point at which it can be evaluated as a single entity, which makes an accurate representation of predicted vs. actual returns somewhat risky. Both of these approaches evolved 30 to 40 years ago within major oil companies. They were strongly influenced by the hierarchical corporate structures of those days, as well as the limited computational and storage capabilities available at the time.

Because most oil and gas companies have been evolving rapidly toward asset-centered organizations, and because dramatic advancements have been made in cost-effective computational power and storage, the methodologies and tools for E&P asset valuation and decision making must be revolutionized to keep pace. Otherwise, the energy industry could squander its most precious resources at a time when global demand is going nowhere but up.
A Novel Technique To Acidize Horizontal Extended-Reach Wells
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 90385, "A Novel Technique To Acidize Horizontal Wells With Extended Reach," by H.A. Nasr-El-Din, SPE, and N.S. Al-Habib, SPE, Saudi Aramco, and M. Jemmali, SPE, A. Lahmadi, SPE, and M. Samuel, SPE, Schlumberger, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.

Extended-reach horizontal wells are drilled to maximize reservoir drainage and minimize water production from coning. A problem with these wells is poor acid distribution during matrix acidizing. The full-length paper discusses a new technique that uses mechanical diversion in the wellbore and chemical diversion in the carbonate formation. A hydraulic tractor was used to pull coiled tubing (CT) to the total depth of the well, and a viscoelastic surfactant-based acid system was used to remove formation damage created by drilling fluids.

Introduction

It is common practice to drill horizontal and multilateral wells to maximize oil recovery in carbonate and sandstone reservoirs. Extended-reach wells are defined as those with a measured-depth (MD) to true-vertical-depth (TVD) ratio greater than 2. Most oil and gas reservoirs are heterogeneous, with significant variations in reservoir permeability. Significant variations in rock permeability in wells with long target zones will cause poor fluid distribution during any chemical treatment. In matrix acidizing treatments, poor fluid placement will adversely affect the outcome of the treatment.

Mechanical and chemical means that can enhance fluid placement are available. Mechanical means, including CT, are used to distribute the fluid across the target zone. Chemical means enhance fluid distribution inside the formation. Several chemical diverters have been used in matrix acid treatments including foam and gelled and in-situ gelled acids. Several authors have raised concerns regarding use of polymer-based fluids in tight formations, especially in sour environments. To overcome some of the problems encountered with polymer-based fluids, viscoelastic surfactant-based acid systems have been used successfully in matrix stimulation. Positive field results were reported when viscoelastic surfactant-based acids were used to stimulate oil producers, water injectors, and water-disposal wells.
Low-Risk TAML Level-5 Multilaterals in the South China Sea
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 88542, "Development of Low-Risk High-Level TAML Level-5 Multilaterals in the South China Sea," by Jonathan Park, SPE, and Duo Wei Shen, SPE, Baker Oil Tools, and Li Wen Yong and Yuan Fu Cun, ConocoPhillips China Inc., prepared for the 2004 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 18-20 October.

The ConocoPhillips Xijiang fields in the South China Sea required multilaterals to increase oil production from the limited number of available platform slots. Further development in this area depended on slot recovery to maximize production and minimize hole collisions caused by frequent sidetracking in cluster wells. This paper discusses a method used to install low-risk multilaterals in these wells. This method reduced the risk and time associated with Technology Advancement of Multilaterals (TAML) Level-5 multilateral completions. This method eliminates the need for a high-risk-washover operation.

Introduction

The Xijiang fields, including the Xijiang 24-3 and Xijiang 30-2 fields and the Xijiang 24-1 satellite field, are approximately 130 km from Hong Kong. The fields are developed with two 24-slot platforms: Platform XJ 24-3 for Xijiang 24-3 field and Xijiang 24-1 satellite field, and Platform XJ 30-2 for the Xijiang 30-2 field.

The Xijiang fields include multiple, laminated production sands from 1400 m true vertical depth subsea (TVDSS) to 2850 m TVDSS. The thickness of the production sands ranges from 1.5 to 92 m, with bottomwater or edgewater drive mechanisms. The porosity of the production sands ranges from 8 to 30%, and permeability ranges from 800 to 8000 md. The unconsolidated production sands require sand-control completions.

The 24 drilling slots on Xijiang 30-2 plat-form were used up in March 2002; the 24 drilling slots on Xijiang 24-3 platform were used up in December 2003. The limitation of drilling slots significantly constrained the future development of Xijiang fields.

To further develop the Xijiang fields, infill wells use sidetracking of existing wellbores. The first sidetrack for the Xijiang 30-2 field was initiated in March 1999; the first side-track for the Xijiang 24-3 field was initiated in June 1999; and the first sidetrack for the Xijiang 24-1 satellite field was initiated in July 2003. As of September 2004, a total of 39 sidetrack projects had been completed. Frequent sidetracking makes hole collisions a significant risk in Xijiang fields.

To maintain daily oil production and increase ultimate recovery in the Xijiang fields, multilateral wells were adopted. Multilaterals reduce hole collision risks. When a well’s production decreases to its economic limit, it becomes a multilateral candidate. Because of the unconsolidated formation around the casing exit, hydraulic integrity and sand exclusion around the junction area in multilateral wells is critical. To optimize production, re-entry into the main bore is required for some sidetracks.
Understanding Torque and Drag: Best Practices and Lessons Learned From Captain Field Extended-Reach Wells
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 91854, "Understanding Torque and Drag: Best Practices and Lessons Learned From the Captain Field Extended-Reach Wells," by G. Rae, SPE, Chevron Upstream Europe, and W.G. Lesso Jr., SPE, and M. Sapijanskas, Schlumberger, prepared for the 2005 SPE/IADC Drilling Conference, Amsterdam, 23-25 February.

Torque and drag (T/D) analysis was used for successful extended-reach drilling (ERD) in the Captain field in the North Sea. The tactics used in overcoming issues such as drill length and the associated risk are explained. The applicability of available T/D-reduction technologies and why many of them were eliminated as possible solutions reinforced the criticality of good T/D analysis on this project.

Introduction

The Captain field is in the U.K. sector of the North Sea, approximately 81 miles northeast of Aberdeen, in a water depth of 369 ft. Because of the high viscosity and low temperature of Captain oil, long horizontal wells are required to drain the reservoirs effectively (Fig. 1). Although the field was discovered in 1977, it was not until 1995 that appropriate technology was available and development approval was received. The field was developed as a phased installation with two drilling centers tied back to a central floating production, storage, and offloading vessel.

Before starting the Captain subsea development, 29 directional wells were drilled in the first, or Area A, development of the Captain field. The requirements of the subsea, or Area B, development were demanding. These were factored into the rig selection and subsequent drilling specification. The Captain sands are shallow, at approximately 3,000 ft true vertical depth (TVD), and soft. The reservoir is thin but prolific. Geosteering or precise directional control in horizontal sections was necessary.

The completion design required a 250-ft straight section (dogleg severity less than 1.0°/100 ft) no more than 350 ft TVD above the reservoir. This section is where the submersible pump would be placed. The design also dictated that the directional build rate shallower than this pump tangent be less than 4.5°/100 ft. The wells would be drilled with water-based mud (WBM) for environmental considerations. A WBM system also was necessary in the horizontal sections to achieve inflow-performance requirements.