bluuebunny/crossref_metadata_2025 huggingface dataset:
Overview: Production Operations (March 2006)
Authors: Poe Bob
Published: February 2015

A strong global demand currently exists for readily useable energy in the form of petroleum and natural gas, and demand has been projected to increase steadily for the foreseeable future. Developed consumer nations are expected to increase consumption of oil and natural gas as their economies continue to improve and expand. Similarly, the energy appetite of developing nations also is expected to increase the demand for petroleum and natural gas, as long as that energy source remains a convenient, economically viable, and environmentally acceptable alternative. The strong demand in global energy needs therefore presents both welcome challenges and boundless opportunities for the petroleum industry. Therefore, the major challenge facing the petroleum industry in satisfying this demand may be the development and application of new or improved methods of finding and producing the required hydrocarbons. As a result, opportunities for the development and implementation of new or improved pro-duction technologies abound in this environment.

Some excellent examples of the opportunities that exist in the industry for novel or improved production technologies are presented in the summaries of the selected technical papers that follow. These examples are but a small sample of the extremely important production-operations issues addressed by the petroleum industry recently, many of which pertain to the modeling and assessment of the production performance of wells. I hope that you find the issues addressed in these technical summaries and the full-length papers, as well as in the additional technical references cited, as interesting and inspiring as I do. With the petroleum industry's efforts to address modern production-operations problems, such as those illustrated by these examples, the challenges presented by increasing demand will invariably present many opportunities for future innovation.

Production Operations additional reading available at the SPE eLibrary: www.spe.org

SPE 95685 "Waterflood Surveillance and Control: Incorporating Hall Plot and Slope Analysis," by D.B. Silin, SPE, U. of California, Berkeley, et al.

SPE 96697 "Modeling Permeability Reduction Caused by Asphaltene Deposition," by A.A. Garrouch, SPE, Kuwait U., et al.

available at the OTC Library: www.otcnet.org

OTC 17152 "Characterization of Hydrate Formation in Black Oil Using NMR," by S. Gao, Rice U., et al.
Overview: HP/HT Challenges (March 2006)
Authors: MacAndrew Robert
Published: February 2015

During my tenure as reviewer for the HP/HT feature, I have seen trends and areas of new activity as well as problems addressed in the papers reviewed each year for inclusion in this feature. This year has been no exception, with a wide range of subjects; showing how the push toward HP/HT production presents challenges to our industry as the boundaries of existing technologies are pushed outward, first slowly and then with more vigor and surety.

The industry is pushing the drilling-technology frontier forward with enthusiasm, despite the high costs. However, the capabilities of available completion equipment are in danger of being left behind this headlong rush by the geological and drilling fraternities. In discussions with those concerned with providing completions for the ever deeper and hotter wells, it is clear that they are, to an extent, struggling with the old problem of the materials world: the lack of any "free lunch." Therefore, completions engineers are engaged in the struggle of finding materials to provide these wells with reliable completions.

One issue, voiced more than once, is the problem resulting from the general reduction in basic engineering research by the major oil and gas companies. As operators reduced their research activities, the service sector has been left to take up the slack. However, one senses reluctance by the service industry to take up the slack. The anecdotal evidence is that the service companies do not feel comfortable taking on the commercial risks involved in developing new or significantly enhanced products. The reasons for this, no doubt, vary from company to company, but if a significant technology gap develops between equipment requirements and availability, then HP/HT developments may stall, or operate with equipment that may have questionable reliability. While not necessarily jeopardizing safety, this gap can present a considerable risk to operating costs. The industry should address this issue to ensure that existing mechanisms of fostering equipment development are functioning and are strong enough to meet the industry's needs.

One last thing: Where are the engineers to drill, complete, and operate these wells? Operators are struggling to fill positions required to produce these generally demanding wells. Requirements to fill these positions are being lowered in the search to find candidates. And once these less experienced candidates are in place, does experience exist within the company to manage these people? Thoughts along the lines of "here we go again" spring to mind!

HP/HT Challenges additional reading available at the SPE eLibrary: www.spe.org

SPE 97018 "Evaluation of Equivalent Circulating Density of Drilling Fluids Under High-Pressure/High-Temperature Conditions," by O.O. Harris, SPE, U. of Oklahoma, et al.

SPE 97582 "Alternatives for High-Strength Materials in Sour Environments," by G. López Turconi, Tenaris, et al.

available at the OTC Library: www.otcnet.org

OTC 17315 "New Bundled Hybrid Risers for HP/HT Applications," by P. Sauvage, Doris Engineering, et al.
Techbits: Meeting Examines History-Matching Advances, Future Challenges
Authors: JPT staff _
Published: February 2015

History-Matching may have made significant advances during the past 10 years, but the lack of industry standards and other challenges could prevent the discipline from being universally accepted. A recent Applied Technology Workshop titled "History Matching: New Developments and Best Practices" identified the current benefits of and future needs for the technique that matches geological models to field production data, with the ultimate goal of predicting future reservoir output.

The meeting's 90 attendees represented a cross section of engineers, geoscientists, and academicians. This diverse group not only had different levels of experience in implementing history matching but also employed many different approaches, which they shared freely. "In general, there was a broad consensus that there is no single best approach to history matching and no uniform approach across the industry," said Akhil Datta-Gupta, who holds the LeSuer Chair of Petroleum Engineering at Texas A&M U. and was Chairperson of the workshop. Many attendees agreed that the approach taken is often tied to the process and the decisions to be made. "It is important to identify model objectives at the outset and define the attributes of a good history match," Datta-Gupta said. "In general, a structured approach to history matching allows us to easily reproduce the results and transfer the technology to younger engineers."

What Is Best, What Is Missing

The five major topics discussed at the Houston-based event were Workflow and Best Practices, Field Applications and Case Studies, Assisted History Matching/Inverse Modeling, Uncertainty Assessment, and New Developments. Within each topic discussion, there were the recurring themes of what is best about today's history-matching technology and what is missing. Mike King, Senior Adviser, Reservoir Modeling and Simulation for BP America Inc., gave the first keynote address, focusing on the extent to which history-matching technology has changed over the past decade. "Ten years ago, SPE held a forum on history matching, and it is interesting to see that some of the techniques addressed then are now reaching a level of maturity where we can apply them," he said.

A decade ago, many geologists and engineers held a negative view of the technology because they thought it was taking reservoir analysis out of their hands. "Over the past decade, our understanding of what the technology can do has matured to the point where people can characterize a reservoir's performance in ways that were impossible just 10 years prior," King said.

Datta-Gupta said the advancements over the past 10 years have taken various forms, and have includedIntegrated-workflow tools.Software for handling and assessing multiple models and simulations.New history-matching algorithms.The use of streamline-based approaches and experimental design/response surfaces.
Swelling Packers Solve Zonal-Isolation Challenge in Oman High-Pressure Wells
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 100361, "PDO's Proactive Approach To Solving a Zonal- Isolation Challenge in Harweel HP Wells Using Swell Packers," by M.S. Laws, SPE, (now with Shell Abu Dhabi B.V.), J.E. Fraser, SPE, and H.F. Soek, SPE, Petroleum Development Oman, and N. Carter, SPE, Easywell UAE (now with Sensornet Ltd.), prepared for the 2006 IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, Bangkok, Thailand, 13–15 November.

The Harweel cluster of reservoirs in southern Oman is Petroleum Development Oman's first enhanced-oil-recovery project. Zonal isolation is crucial to the success of the planned miscible-gas-injection project. Previous isolation attempts using cementing technology alone have proved to be unsuccessful. On the basis of results obtained from both laboratory and field tests, swelling packers in combination with cement have demonstrated zonal isolation in these challenging high-pressure reservoirs. This could enable a significant increase in reserves and, hence, ultimate recovery in these fields.

Introduction

The Harweel cluster consists of nine different deep, highly pressured reservoirs containing sour, light hydrocarbons. More than 50 wells have been drilled in and around these fields. The initial wells have a shallow 13 3/8-in. surface casing, a long 9 5/8-in. production casing, a 7-in. liner cemented over the reservoir section, and 3 1/2-in. production tubing.

The cluster is being developed in a phased manner. The objective of Phase 1 was to gather data from a number of different sources to determine if a miscible-gas-injection project would be feasible in some of these fields. Phase 2 will involve primary depletion in a number of fields followed by gas injection in some, and Phase 3 will involve clusterwide depletion and gas injection in the remaining fields. To maximize ultimate recovery from these fields, gas (and water) shutoff is required during Phases 2 and 3 of the project. For this to be effective, zonal isolation over the reservoir is essential.

A substantial effort has been expended during construction of the Phase 1 wells to determine if zonal isolation was being achieved with standard cementing techniques. Cement-bond logs were run over the liner section in every well to determine cement quality. These logs showed that a microannulus was being created in practically every case. During well completion, cement debonding from the production liner occurs as a result of differential-pressure effects that lead to creation of a microannulus. Once the microannulus is created, a permanent flow path between the cement and production liner can be created, preventing zonal isolation.

Selective perforating during the subsequent well-testing campaign showed that this microannulus was conductive to reservoir fluids (Fig. 1). In one incident, reservoir fluids leaked all the way to surface through the microannulus.
Q&A with Emmanuel Egbogah, Special Adviser to the President of Nigeria on Petroleum Matters
Authors: Egbogah Emmanuel O. , Donnelly John
Published: February 2015

Q&A

Regarding your new appointment as special adviser to the President of Nigeria on Petroleum Matters, what does your position involve?

My position is to advise the president of Nigeria on anything to do with petroleum, including legal aspects, policies, and strategies. The Nigerian petroleum industry is my responsibility. In the immediate term, I am involved in the restructuring of the public sector of the oil and gas industry in Nigeria. That is my immediate task because in the past the oil industry has not done as well as it should have. A lot of the laws are very old and out of date so I am involved in updating laws and policies. We are repealing many laws and enacting new ones to be able to make the changes in the industry that we want to occur. Those changes are very fundamental and very profound and will change the way the oil industry operates in Nigeria.

Can you describe what kinds of changes you would like to see happen?

For instance, we have created a structure that derived from the highest level of authority in the government, what we call a superministerial council, the National Energy Council, which will be chaired directly by the president himself. This council, which includes ministers of the government and myself, will supervise the restructuring and the complete reorganization of the national oil company, the Nigerian National Petroleum Corporation (NNPC). In the past, NNPC has engaged in what I call a conflicting role in legal, commercial, and regulatory policies. It is not possible that a company could police itself, so we are now going to separate the various functions of the company.

The new company, which is going to be called the National Petroleum Company of Nigeria, will engage purely in commercial activities and function as an integrated national company that can go to the stock market and raise money to carry out its operations. It will be regulated by a new agency, called the Petroleum Inspectorate Commission, which replaces the Department of Petroleum Resources in Nigeria. That commission will have the authority to regulate, including the international oil companies (IOCs) operating in the country.

We will have a dual regulation structure—one body to oversee the upstream and another to oversee the downstream, called the Petroleum Development Administration. These functions will be clearly defined so that the roles no longer will be conflicting and self-defeating. We believe that this kind of structure will give clarity, efficiency, and professionalism to the oil and gas industry in Nigeria.
Crystallography: The Long-Term Price of Oil
Authors: Moncrieff Ian
Published: February 2015

Management

It seems only the proverbial blink of an eye since the principal determinants of the price of crude oil on world markets were the tax-paid cost of the Burgan field in Kuwait and the producing allocations decided by the Texas Railroad Commission. Crude oil was in such abundant supply 50 years ago that British Petroleum, then half-owner of the Kuwait concession, and the world's largest oil producer by far, sold more than half a million BOPD of its share of production to its partner, Gulf Oil, at the overlift price, one-eighth way between the accounting cost of production (then about USD 0.80/bbl) and the posted price of USD 1.75. Gulf Oil turned around and resold most of its Kuwait overlift oil at a larger profit, and nobody seemed to care. The world was awash in oil. On the domestic front, supply was so abundant that Texas oil wells were permitted to pump for only 97 days in 1958.

Suffice it to say that we no longer exist in a world of oversupply. West Texas Intermediate (WTI) futures on Nymex briefly crossed the USD 100/bbl threshold in late 2007. Alberta has become the new Kuwait, and the Texas Railroad Commission figuratively relocated from Austin to Vienna and became OPEC. Like the Seven Sisters before them, OPEC has attempted to control the price of oil on world markets, with Saudi Arabia shouldering the role of market regulator. While the majors showed impressive solidarity in their dealings with foreign governments, the supply fundamentals were not in their favor. The nationalization of IPC's holdings in Iraq, for example, was precipitated by the refusal of the majors to develop new Iraqi oil fields when there was already too much oil on the market.

So what has happened to trigger the more than seventy-fold increase in the price of oil since the 1960s, when the arm's-length price of Kuwait crude was around USD 1.35/bbl, and what lessons may we glean from this history as we peer intently into the crystal ball of price predictions?

The Lessons of History

As Winston Churchill famously remarked, "Those that fail to learn from history are doomed to repeat it." Three principal forces have been at play over the past 50 years, and we would be remiss in ignoring them.Population and economic growth, which powered world consumption of refined products to grow from 21.3 to 84.4 million BOPD between 1960 and 2006.Cumulative oil production since 1960, which, notwithstanding published recoverable-reserves estimates to the contrary, exceeded reserves additions.The remarkable adaptability of consumers to higher prices, abetted by frequently undisciplined or short-sighted government policies that encourage inefficient use of transportation fuels.
Your SPE: SPE Meetings Evolve to Respond to Technology Needs
Authors: Roodhart Leo
Published: February 2015

President's column

SPE's principal aim is the transfer of technology. This is achieved in a number of ways, including events, publications, and online resources. I believe we are successful in this mission, which largely accounts for why the Society has a growing worldwide membership.

One of SPE's proudest traditions is the longstanding and continuing quality of its events. My schedule as President is driven partly by major SPE events; if I can combine attendance at a conference with a visit to local sections, this is the ideal trip and potentially adds the most value for SPE and its members. Since I have so much to say about technology transfer, I am focusing this month on events and will talk next month about publications, online resources, and other exciting future plans.

Some of the oldest SPE events still retain their top billing in the oil industry calendar, as they have evolved over time to meet the requirements of delegates and exhibitors alike. Offshore Europe, for example, held every 2 years in September in Aberdeen, has come a long way from its early beginnings in the mid-1970s when the event was held in marquees at the University of Aberdeen. The 2007 show broke all previous attendance records, with daily visitors in excess of 40,000 and over 1,450 exhibitors. The 2009 show has grown another 10% in size and has a waiting list for exhibit space. The international presence has never been greater, with pavilions from all parts of western Europe, three large pavilions from China, and, for the first time, from Spain and Brazil.

One of the most exciting developments over the past 10 years is the addition of major exhibitions and conferences in places like Latin America and Russia. As SPE membership becomes more international, we need to take quality events to more corners of the globe to encourage maximum participation. As is the case with the more established shows, these events feature a more interactive debating style, which makes for much livelier and interesting presentations. This does not detract from the quality of technical information presented; indeed, SPE is way ahead of the commercial event organizers and many professional societies in its system of first requiring technical papers for most of its conferences and then archiving all conference papers for reference by members worldwide in the SPE eLibrary and in the multi-society OnePetro. I will talk more about this next month.
Comments: Price Swings
Authors: Donnelly John
Published: February 2015

Editor's column

A new report from Ernst & Young seeks to find a bottom for commodity prices and any signs that might point to economic recovery. Among its findings are that the recent oil price fall was the steepest ever, at 75%, and that past price corrections have lasted an average of 73 weeks before recovering. Because recessions eventually have given way to economic resurgence that relies heavily on energy, the report concludes that now is the time for the oil and gas industry to prepare for economic recovery by continuing to drill, ensuring that it is retaining talent, and investing in alternative fuels.

Others have sounded a similar note of late. At last month's annual Cambridge Energy Research Associates (CERA) conference, executives from BP, Shell, and other firms noted the importance of continued investment in energy. Robust long-term growth forecasts for hydrocarbons have not changed, and the industry could be caught flat-footed when the recovery comes if it shuts down too much now. Shell Chief Executive Jeroen van der Veer said he believes that global energy demand still will double over the next 40 years, boosted by consumption from the developing world. BP Chief Executive Officer Tony Hayward also showed optimism. "The world economy will recover," he said. "The future is not canceled." (For additional reporting on the event, go to JPT Online at www.spe.org/jpt.)

The statements lend credence to the idea that many in the industry are trying to avoid some of the mistakes of the past, when R&D and staff were sharply cut in the wake of down cycles. But nothing paralyzes the oil market so much as price instability. After the steep drop in prices in the second half of last year, oil seemed to be recovering, only to fall again and remain volatile. Such unexpected swings deter decisions about investment, particularly those projects with sensitive price thresholds such as oil sands and unconventionals.

Volatility also hampers merger and acquisition activity. Sellers are reluctant to shed assets at low prices while potential buyers continue to sit on cash. "Nobody has been willing to pull the trigger. Everybody has been waiting for the upside," said IHS executive Linda Kinney at a conference last month in Houston sponsored by the consulting firm.

Daniel Yergin, Chairman of CERA, says the oil markets "are suffering acute whiplash" and that the price volatility since mid-last year is causing confusion and uncertainty. The International Energy Agency says a shortage of capacity was really at the center of the steep run-up in prices that ended last year. Although "speculation" may have played a role, it was really the fundamentals of supply and demand that drove the market. Strong growth from places such as China and India exploited years of industry underinvestment in both the upstream and downstream, constraining supplies. It expects a similar tightness could occur in just a few years after the global economy fully emerges from what appears to be a severe recession.
Permanent Reservoir Monitoring in Subsea Wells Attains New Level
Authors: Lovell John , Mackay Stuart
Published: February 2015

Technology Update

Some material in this article has been previously published in papers SPE 116474 and 116476, presented at the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21-24 September. The figures for this article originally were published in paper SPE 116474.

Despite the credit crunch, worldwide subsea activity is still forecast to grow rapidly. In its recent 2009 subsea forecast, Infield Systems indicated that subsea drilling and completion expenditure will more than double to USD 80.5 billion between 2009 and 2013, from a total of USD 31.9 billion during the period from 2003 to 2007 (Infield 2009). Coupled with the increase in expenditure, Infield forecasts 3,222 subsea wells to be installed from 2009 through 2013, vs. 1,958 wells installed between 2004 and 2008. A large percentage of these wells will require sand control.

In market-share terms, Infield forecasts that Africa will remain the largest sector, representing 29% of the forecast capital expenditures between 2009 and 2013, followed by North America (25%), Latin America (19%), and Europe (13%). The remaining spending will be spread between Australasia, Asia, and the Middle East and Caspian region.

Despite this growth in the number of subsea wells, the expense of subsea well intervention often leads to insufficient reservoir information for accurately understanding reservoir connectivity, drainage, and flow assurance. This has led to an industry need for real-time data from sensors located on the sandface. For those wells requiring sand control, an additional constraint is that sandface sensors must be deployed on a separate completion run.

Reservoir-Monitoring Challenges in Dual-Stage Completions

Most wells with sand control use completion components that are deployed in multiple stages. This presents a challenge to achieving measurements from monitoring equipment located in the lowest stage of the completion because sensor power and data are required to be transferred across the junction between the lower and upper completion stages.

Consequently, reservoir monitoring in dual-stage completions has generally been limited to measurements of pressure and temperature near the production packer in the upper completion. These types of sensors cannot distinguish the downhole conditions of individual zones. Placing the sensors at the sandface, where the fluid enters, would take permanent monitoring to the next level because it enables operators to better understand the flow from each producing zone. This has now been achieved by an operator in southeast Asia who has deployed the Schlumberger WellWatcher Flux digital-sensor array system onto the screens of six openhole gravel packs in a subsea gas field. Data from those sensors has been transmitted to shore during cleanup, with the output used to make interpretations of permeability and cleanup efficiency for each producing zone.
Techbits: Deepwater Developments Focus of Mumbai Workshop
Authors: JPT staff _
Published: February 2015

Techbits

Deepwater discoveries and development plans are expanding from well-established regions like the US Gulf of Mexico (GOM) to frontier regions such as offshore India, but there is a lag in experience that must be filled. An SPE Applied Technology Workshop (ATW) in Mumbai titled "Deepwater Development" aimed to do that, by bringing together a multidisciplinary, multinational group of 117 oilfield professionals to exchange ideas in the area of deepwater project planning and execution.

Workshop Steering Committee Chairperson N.K. Mitra of Oil and Natural Gas Corporation (ONGC) welcomed all delegates and presented an overview titled "Deepwater: An Indian E&P Perspective." He highlighted India's deepwater potential, which includes 1.35 million sq km of sedimentary area containing 10 billion bbl of reserves. He described ONGC's successful deepwater drilling effort at Sagar Samridhi in August 2003 that resulted in the discovery of the G-1, GS-15, and Vashishtha fields, which are scheduled to begin production in 2010–2012. Challenges preventing further deepwater developments in the region include drilling and completion technical hurdles, flow assurance, and a resistance to changing mind sets.

In the keynote address that followed, A.K. Balyan with ONGC saw an urgent need to increase deepwater exploration and development off the coast of India to stem its dramatically increased petroleum import bill. This will require increased cooperation among all players in the areas of reservoir management and drilling, as well as further technology optimization.

ONGC's R.S. Sharma, the chief guest of the ATW's inaugural session, pointed to nonavailability of deep- and ultradeepwater drilling rigs as driving rig costs to stratospheric levels, and estimated that each second of lapsed drilling activity at a site costs USD 146. He felt that the speed of technology development has not been keeping pace with industry needs, and placed emphasis on the areas of deepwater equipment standardization, technology for high-pressure/high-temperature (HP/HT) wells, and smart completions.

Case Histories

The first technical session reviewed two deepwater case histories. The first out-lined the planning and execution of the Shell NaKika project in the US GOM.

Integration of several new deepwater technologies from various disciplines and an integrated team of experienced people, from subsurface planning to operations, were the keys to the success of the NaKika project.

The second case study reviewed StatoilHydro's overall deepwater development and management philosophy which gives high priority to efficient inspection, maintenance, and repair. The Kristin field, with a three-stage overpressure protection design, is an example of StatoilHydro's experience with HP/HT wells.
Options are Running Out - Today's Youth Needs Convincing
Authors: Hopkins Chris
Published: February 2015

Talent & Technology

Recently, I was part of the SPE Colloquium on Petroleum Engineering Education, an event comprising academia and industry professionals assembled to address the issue of personnel recruitment and training in the oil and gas industry. Representatives of international universities, major and independent operators, and the service and supply industry took on the challenge of answering the burning question, "How are we going to identify, recruit, hire, and train the professional employees we need for the future?"

Facing the Hard Facts

Forecasts vary, but some estimates indicate that production from existing fields will decline from current levels of around 75 million B/D to approximately 15 million B/D by 2030. To meet anticipated demand, production will need to be approximately 115 million B/D or higher. How will we fill the gap? Most will come from new exploration and development of known reserves, the remainder from enhanced-oil-recovery (EOR) techniques and unconventional sources such as heavy oil or shale oil. But getting oil from these sources will require concentration on trained people, optimized processes, and innovative technology.

Technology has kept pace through the years, allowing us to access reservoirs in more than 10,000 ft (3049 m) of water, drill extended-reach wells as far as 7.6 miles from the surface location and geosteer through thin sections of less than 10 ft (3.1 m) for more than a mile. Innovative use of technology has also helped advance industry achievements. Today, thousands of wells are equipped with monitoring systems that allow automatic 24-hour production surveillance with data transmission to a central production-management facility. This allows operators to manage by exception, focusing on problem wells instead of poring over spreadsheets of data on wells that are performing normally. New automated workflows provide operators with actionable information instead of raw data taking seismic all the way to simulation. These workflows can condense geological interpretation time from 3 years to 6 months (Fig. 1).

Although technology and workflow processes are providing the leverage to accomplish some of the demand, these two alone are not strong enough to support the industry. We must have well-trained people.

The Obstacles

Based on a benchmark survey conducted by Schlumberger Business Consulting (SBC) of 30 companies, the long feared "big crew change" is upon us and we are not recruiting the numbers to meet this need. At the present time, we are meeting demand with 40% of the geology and geophysics graduates entering the oil and gas industry (Fig. 2). But to meet the future demand, SBC has estimated that 80% of students would have to go into petroleum geology. Currently students are going into mining, hydrology, or environmental work. Many graduates in geophysics study earthquakes, volcanoes, or get into soil and rock mechanics for the construction industry.
Technology Focus: Hydraulic Fracturing (March 2009)
Authors: Chipperfield Simon
Published: February 2015

Technology Focus

"Besides black art, there is only automation and mechanization."—Federico Garcia Lorca, Spanish poet and playwright (1898–1936)

On this basis, fracture stimulation sits firmly in the realm of mysticism, crystal balls, and tarot.

The reason for this is that unlike automation (e.g., car manufacturing) we still are uncertain of what makes fracture stimulation "work" (i.e., the critical components) and of how we evaluate and improve performance (i.e., of what constitutes a "vehicle service").

The car industry understands the components that make a car operate because each is built meticulously and repetitively. The key components that drive fracture stimulation are more difficult to determine because the process is subject to a high degree of variability in subsurface conditions. And what adds more "smoke and mirrors" to stimulation design is that much of the research that forms our basic understanding was developed more than 30 years ago on tight gas reservoirs, which bear no resemblance to the shale, coal, or unconsolidated sands stimulated today. In other words, while we have paid for a Rolls Royce we unwittingly may be driving a DeLorean.

The automotive industry assesses the performance of its cars through periodic, thorough checkups. How often do we conduct a multicomponent service on our stimulation treatments? Microseismics, continuous reservoir monitoring (by use of distributed-temperature surveys and permanent downhole gauges), and radioactive-fluid tracers are some of the technologies used to determine the "health" of stimulation treatments. Their use, however, remains the exception not the rule. Usually, expensive stimulation-treatment checkups are avoided; instead, only the oil dipstick continues to be used (i.e., pressure and rate during injection and production).

Is it not time that you better understood the key components "under the hood" and gave a complete service to your fracture-stimulation process? Only through better understanding will the "black art" be replaced by science, the performance be measured, and step changes truly be made.

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

SPE 116124 • "Case History of Sequential and Simultaneous Fracturing of the Barnett Shale In Parker County" by P.N. Mutalik, Williams Companies, et al.

SPE 118831 • "Optical-Fiber Distributed Temperature for Fracture-Stimulation Diagnostics and Well-Performance Evaluation" by Paul Huckabee, SPE, Shell E&P

SPE 119350 • "Stress Amplification and Arch Dimensions in Proppant Beds Deposited by Waterfracs" by N.R. Warpinski, SPE, Pinnacle

SPE 111431 • "New Viscoelastic Surfactant Fracturing Fluids Now Compatible With CO2 Drastically Improve Gas Production in Rockies" by K. Hughes, Chevron, et al.
Development and Use of High-Density Fracturing Fluid for Deepwater Frac Packs
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 116007, "Development and Use of High-Density Fracturing Fluid in Deep Water Gulf of Mexico Frac and Packs," by L. Rivas, SPE, G. Navaira, SPE, and B. Bourgeois, SPE, Chevron, and B. Waltman, SPE, P. Lord, SPE, and T. Goosen, SPE, Halliburton, originally prepared for the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21-24 December. The paper has not been peer reviewed.

There has been an increase in the number of wells drilled to depths greater than 20,000 ft in the Gulf of Mexico (GOM). Because of the high fracture gradient and friction in the wellbore tubulars, a conventional 1.0- to 1.04-specific-gravity (SG) fracturing fluid would require surface treating pressures greater than 15,000 psi, which exceeds the limit of the flexible treatment line. To solve this problem, a borate-crosslinked high-density fracturing (HDF) fluid with SG of up to 1.38 was developed to reduce the amount of surface treating pressure required to achieve adequate bottomhole fracturing pressure.

Introduction

The Tahiti field is in the GOM in the Green Canyon area where water depths range from 4,000 to 4,300 ft. The discovery well was drilled in 2002. Total depth was more than 28,000 ft. Initial evaluation indicated approximately 400 ft of net pay in the high-quality reservoir sand that was encountered. Subsequent appraisal drilling over the next 2 years resulted in confirmation of the size of the Tahiti field and its status as one of the most significant net-pay accumulations ever discovered in the GOM. The discovery well was re-entered in 2004, and a well test was performed to verify deliverability, dynamic well data, and reservoir properties. A stacked frac pack in the Miocene M21A and M21B sands was planned for the well test. The Tahiti M21A sand averages 60 to 80 ft thick, and the M21B sand averages 120 to 150 ft thick. Permeability ranges from 600 to 800 md. The decision was made to complete both intervals with a single, high-rate frac pack. At the time, at a depth in excess of 25,800 ft, it was the deepest successful well test and frac-pack completion ever carried out in the GOM. The HDF fluid was a key component of the successful Tahiti well test. The well-test results led to the development of the Tahiti field, which began in February 2006.

While planning the Tahiti well test, several factors influenced the decision to develop a suitable HDF fluid that would minimize surface treating pressures and allow the fracture job to be pumped at pressures below the 14,000-psi limit. Uncertainty regarding Miocene-pay-sand fracture gradients, and required treating rates, coupled with high friction losses in the treating string led to the desire to find an HDF fluid that would allow the fractures to be pumped at 40 to 45 bbl/min while staying within surface-treating-pressure limitations.
Technology Focus: Production Operations (March 2009)
Authors: Alhanati Francisco J.S.
Published: February 2015

Technology Focus

If you are involved in production operations, you probably are dealing with at least one, likely more than one, of the following tough challenges: deepwater subsea; arctic environment; complex wellbores (e.g., highly deviated, long horizontal sections); high-pressure/high-temperature; heavy/viscous oil; or conditions favoring sand production or deposition of scale, paraffin, asphaltenes, or hydrates; or the formation of tight emulsions. In addition, you also have to figure out the best way to manage the produced water and keep corrosion under control. Hey, this is what makes our jobs fun, right?

Fortunately, despite the hectic pace in the industry these days, many of us are still making time to write papers and make presentations at technical conferences, sharing ideas and hands-on experiences. This past year alone, almost 200 SPE papers related to production operations have been presented. And this number does not include papers that deal specifically with artificial lift, wellbore completions, or production facilities. The papers featured in this issue, therefore, can give you only a small sample of the vast amount of the good material that is out there. Enjoy the reading and search for more at the SPE eLibrary.

Production Operations additional reading available at the SPE eLibrary: www.spe.org

SPE 114106 • "The Cost and Value of Field, Laboratory, and Simulation Data for Validating Scale-Inhibitor-Treatment Models" by J.A. Patroni Zavala, Heriot-Watt University, et al.

SPE 116673 • "Sand or Mud Removal in Low-Bottomhole-Pressure Wellbores Using Jet Pump and Concentric Coiled Tubing Leads to Improved Production" by J. Li, BJ Services, et al.

Additional reading available at OnePetro: www.onepetro.org

OTC 19612 • "Swellable-Packer Technology Resolves Water-Production Problem—Case History in Campos Basin, Brazil" by Eduardo Midulfo Ueta, Petrobrás, et al.
Protect Electrical Submersible Pumps by Squeezing Scale Inhibitors
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 115195, "Squeezing Scale Inhibitors to Protect Electric Submersible Pumps in Highly Fractured, Calcium Carbonate Scaling Reservoirs," by Neil Poynton, SPE, Alan Miller, Dmitry Konyukhov, and Andre Leontieff, Baker Hughes, and Ilgiz Ganiev and Alexander Voloshin, SPE, Ufanipineft, prepared for the 2008 SPE Russian Oil & Gas Technical Conference and Exhibition, Moscow, 28-30 October. The paper has not been peer reviewed.

Electrical submersible pumps (ESPs) can increase production rates, but run time can be compromised by the formation of scale inside the pump. Eventually, the pumps fail (either mechanically or electrically) and must be replaced. Examination of failed pumps indicated the main failure mechanism was deposition of calcium carbonate scale inside the pump. Testing was performed to identify and develop scale-inhibitor squeeze chemistries suitable for appli-

Introduction

Yuganskneftegaz is Rosneft's largest oil-producing enterprise. It holds licenses to develop 26 oil fields in the Khanty Mansiysk Autonomous District of western Siberia.

Yuganskneftegaz's primary fields are Priobskoye, Prirazlomnoye, Mamontovskoye, and Malobalykskoye. The number of wells on production in 2006 was 7,707. The average production per well was 21.3 tonne/d in 2006.

Typical well completions in the Priobskoye field have the following characteristics.Internal casing diameter of 131 or 157 mm (a few with 160 mm)Outside diameter of the production string of 73 mm (a few have 80 mm)Pump depth at 2300 to 2800 mDepth to perforation of 2500 to 3000 mPermeability from 3 to 20 md

Produced water has a calcium carbonate scale potential, which negatively affects ESP run time. Testing identified a suitable squeeze inhibitor, and a model of the application identified the squeeze-treatment sensitivities.

Scale-Prediction Modeling

Commercially available scale-prediction software was used to determine scaling tendencies at different pressures and temperatures for brine chemistries from several Priobskoye wells. An understanding of the scaling risk was developed, and suitable scaling brine was identified for use in the subsequent laboratory inhibitor-selection process. Simulations were performed at bottomhole flowing conditions, for estimated ESP internals, and at well-head conditions.

Scale-prediction results for the different wells followed a similar trend. Three scale species were predicted—iron carbonate, calcium carbonate, and barium sulfate. Of these species, barium sulfate was the least significant, and, where present, the tendency was very mild. Calcium carbonate tendencies ranged from moderate to severe. The pH value at standard temperature and pressure also was calculated with the model, and the results correlated very well with the pH measured in the field.
Integrated Approach to Formation-Water Management: From Reservoir Management to Protection of the Environment
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 116218, "The Integrated Approach to Formation-Water Man agement: From Reservoir Management to Protection of the Environment," by Jose G. Flores, SPE, and Jon Elphick, SPE, Schlumberger, and Francisco Lopez and Pablo Espinel, Agip Oil Ecuador, prepared for the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21-24 September. The paper has not been peer reviewed.

Most fields in the Oriente basin of Ecuador and neighboring Marañón and Putumayo basins in Peru and Colombia, respectively, produce large volumes of water. In most cases, as the water cut increases, oil production is restricted, which creates production problems including scale deposition, corrosion, and sand production. An integrated approach to formation-water management begins with an understanding of the water-flow mechanisms in the reservoir and identifying the water-breakthrough mechanism at the producer well, followed by the detection of production bottlenecks in the wellbore and surface facilities, and then finishing with analysis of water disposal or reinjection.

Introduction

Villano is a heavy-oil field in a tropical rainforest area in the Province of Pastaza in the Oriente basin of Ecuador. Discovered in 1950, it began producing in 1999. Because of concern for the environment and native communities in the area, development was performed in an offshore-type fashion. With no road access, all transport was provided by helicopter. The drilling and production facilities are limited to two well pads, V-A and V-B of approximately 4 and 2 hectares, respectively. Pad V-A hosts a drilling and a workover rig, drilling warehouses, well pads, living quarters, production facilities to dehydrate the oil, and transfer pumps to transport the oil through a 12-in.-diameter 44-km-long pipeline to the central processing facility (CPF). Formation water is disposed of at Pad V-A into two water-disposal wells (WDWs). Pad V-B is a remote wellsite with limited facilities. Particularly relevant in the effort was construction of the aerial 12-in. pipeline, built without road support and with a minimum effect to the rain forest environment.

The Villano structure was developed primarily with horizontal wells. Sixteen wells have been drilled in Villano—13 producers, all fitted with electrical submersible pumps (ESPs); two WDWs; and one discovery well (V-1), which has been abandoned. There are two additional WDWs at the CPF. All the production is from and water disposal is into the Hollín formation, of Cretaceous age.
Electrical Downhole Heaters for Faja Heavy-Oil Reservoirs
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 117682, "Feasibility of Using Electrical Downhole Heaters in Faja Heavy-Oil Reservoirs," by Raul Rodriguez, SPE, Jose Luis Bashbush, SPE, and Adafel Rincon, SPE, Schlumberger, originally prepared for the 2008 SPE International Thermal Operations and Heavy Oil Symposium, Calgary, 20-23 October. The paper has not been peer reviewed.

The full-length paper examines use of downhole heaters in thick sands stimulating vertical and horizontal wells, evaluates temporary application of downhole heaters in horizontal wells for a limited period of time, and covers basic economic analyses.

Introduction

The Orinoco belt (Faja) in Venezuela contains one of the largest resources in the world of heavy and extraheavy oil. Because of the production decline of conventional light crude, projects must focus on increasing the recovery of heavy and extraheavy oils by use of thermal and nonthermal methods. Steam-based thermal-recovery processes are more efficient in low-pressure reservoirs; however, because of their depth, the initial pressures of the reservoirs in the Faja are relatively high, ranging from 600 to 1,500 psi with viscosities typically greater than 2,000 cp. For these reasons, it is important to decrease the pressure of the reservoirs with primary-production techniques to facilitate the economical implementation of steam-injection-based methods.

The initial production of heavy and viscous oils can be accelerated by use of downhole heaters that, by providing energy to the vicinity of the well, decrease oil viscosity and increase the oil-production rate. A consequential advantage of using downhole heaters as a prelude to a steam-injection process is that they accelerate early production and reservoir-pressure depletion.

Electrical Downhole Heaters.

Electrical heating consists of providing electrical currents to generate heat and increase the temperature near the wellbore. There are two kinds of downhole heaters in use by the oil industry: inductive heaters, generating heat in accordance with Maxwell's law, and resistive heaters that generate heat in accordance with the Joule effect. In the latter case, the heat transfer is by conduction and it requires an extended time period to heat the reservoir.

In this study, the resistive heater is modeled with the aid of a numerical thermal simulator. This type of heating process stimulates oil recovery primarily by reducing the oil viscosity in the near-wellbore region and secondly by thermal expansion of reservoir fluids. The key parameters to be understood in this process are the heavy-oil-viscosity variation with temperature and the rate of heat provided by the heater associated with the generated temperature gradient in the volume around the well. Heat output from resistive heaters typically ranges from 14 to 730 W/ft (1,100 to 60,000 Btu/D/ft). A maximum-exposure temperature normally is imposed on the heaters.