bluuebunny/crossref_metadata_2025 huggingface dataset:
Hydrostatic Packers Manage Lost Returns, Well Control, and Cement Placement
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 112657, "Use of New Hydrostatic-Packer Concept To Manage Lost Returns, Well Control, and Cement Placement in Field Operations," by F.E. Dupriest, SPE, ExxonMobil Development Company, originally prepared for the 2008 IADC/SPE Drilling Conference, Orlando, Florida, 4-6 March. The paper has not been peer reviewed.

A hydrostatic packer consists of a column of light fluid pumped into the annulus or drillstring to cause the total hydrostatic head (HH) to be equal to or less than the integrity, which is a function of the fracture-closure stress (FCS). This results in a positive surface pressure that allows accurate placement of cement, lost-returns treatments, or other fluids in situations where they otherwise would be overdisplaced if a full column of drill-weight mud were used. The operator has used hydrostatic packers in one area for 15 years and globally for the last 7 years.

Introduction

The majority of severe losses are a result of fracture propagation, and this is the type of loss where hydrostatic packers are used. Fracture-propagation losses occur when wellbore pressure exceeds the integrity, which is largely composed of the far-field stress holding the borehole closed plus some lesser near-wellbore stress effects. When wellbore pressure forces the rock open, a tall, narrow fracture is formed. Drilling fluid then propagates and extends the fracture, and losses continue. After the fracture is created, the adjacent formation stress continues to attempt to close it. This stress is referred to as the FCS. The FCS may increase slightly because of a variety of effects, but it cannot fall below the minimum far-field stress. As long as the wellbore pressure exceeds FCS, losses and fracture growth will continue. Conversely, if wellbore pressure is reduced below FCS, the far-field stress forces the fracture closed and losses stop.

The behavior observed at the surface when the HH exceeds the FCS is that the well will not stand full. The lost-returns fracture opens because the force holding the rock closed is less than the static head (force) being applied. Because of well-control concerns, the common practice then is to fill the annulus continuously with drill-weight mud. Losses continue as long as the annulus is filled because the head remains higher than the resisting FCS at the loss zone. The FCS continues to exert a constant and reliable force against the bottom of the fluid column, but losses continue because the FCS is unable to support a full column of drill-weight mud.
Improving Well Safety With an Innovative Surface-Controlled Subsurface Safety Valve
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 113829, "Improving Well Safety and Maximizing Reserves Using an Innovative Surface- Controlled Subsurface Safety Valve (SC-SSSV)," by Francois Millet, SPE, Harve Petit, and Gery Wallez, Geoservices Equipment, and Philippe LaLanne, Alain Ducasse, and Emile Barzu, Total E&P France, originally prepared for the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21-24 September. The paper has not been peer reviewed.

A common cause of failure of surface-controlled subsurface safety valves (SCSSSVs) is a defect in the downhole hydraulic line that controls the valve from the surface. Such a failure generates production losses and requires the intervention of a costly workover rig. To alleviate this type of situation, a system has been developed in which the physical control line has been replaced by a communication system based on electromagnetic (EM) waves. The surface emitter continuously sends a signal to the SCSSSV. Both are designed to be fail-safe.

Introduction

Lacq field was developed from 1951 to 1957, while solving metallurgical constraints caused by the 15% H2S and 10% CO2 in its gas composition. Nearby, three other fields produce the same long and narrow reservoir and started production in late 1967. From 1968 to 1982, gas production reached approximately 33×106 m3/d, the production from the four fields being centralized at the Lacq treatment plant.

These fields are now at the end of their life. The last well was drilled at the end of 1990. Since 1957, well pressures have dropped from 70 MPa to as low as 2 MPa. Unstable water production started in the early 1980s on some wells in the Meillon and Saint Faust fields, causing high operating costs because of water-disposal problems. Furthermore, the normally open velocity and ambient valves used on some wells are no longer acceptable because unstable flowing conditions do not allow accurate and repetitive closure.

To extend the life of the wells and maximize the recovery factor, Total E&P France has been looking for a solution to replace subsurface-controlled safety valves (SSCSVs) and nonfunctioning SCSSSVs with new SCSSSVs without the need for a work-over. One solution is surfactant injection at the reservoir level. In this case, the challenge is to free the available nipple and set an injection device in the nipple, again without any work-over or wellhead modification.

Avoiding WorkoverThere currently are two types of safety systems being used.The SSCSVs are wireline retrievable (WR) and are calibrated well by well according to the latest production conditions. They are less and less compliant with safety regulations.The SCSSSVs are fail-safe production-rate independent, and testable from the surface whether they are tubing retrievable (TR) or WR.
Relevance (February 2002)
Authors: Holditch Stephen A.
Published: February 2015

President's column - No abstract available.
Leading by Example
Authors: Kamal Medhat M.
Published: February 2015

Guest editorial - No abstract available.
Techbits (February 2002)
Authors: JPT staff _
Published: February 2015

Techbits - No abstract available.
3D Ground-Penetrating Radar Used to Map Reservoir Analogs
Authors: Wallace Rhea
Published: February 2015

Technology Update - No abstract available.
Drill Cuttings Reinjection
Authors: Bybee Karen
Published: February 2015

This article is a synopsis of paper SPE 72308, "Design Considerations in Drill Cuttings Reinjection Through Downhole Fracturing," by Ahmed S. Abou-Sayed, SPE, and Quanxin Guo, SPE, Advantek Intl., originally presented at the 2001 IADC/SPE Middle East Drilling Technology, Bahrain, 22-24 October.
First High-Pressure, High-Angle Well in Kuwait
Authors: Bybee Karen
Published: February 2015

This article is a synopsis of paper SPE 72299, "First High-Pressure, High- Angle Well in Kuwait: Case Study of WMN-2," by M. Al-Saeedi, SPE, Kuwait Oil Co.; R. Munger, SPE, and P. Tooms, SPE, BP Kuwait; B. Al-Mutairi and K. Al-Quraini, SPE, Kuwait Oil Co; J. Decaire, Kuwait Drilling Fluids; and T. Tuncer, SPE, Schlumberger Oilfield Services, originally prepared for presentation at the 2001 IADC/SPE Middle East Drilling Technology Conference and Exhibition, Bahrain, 9-11 March.
Chemical and Thermal Effects on Wellbore Stability of Shale Formations
Authors: Bybee Karen
Published: February 2015

This article is a synopsis of paper SPE 71366, "Chemical and Thermal Effects on Wellbore Stability of Shale Formations," by M. Yu, G. Chen, SPE, M.E. Chenevert, SPE, and M.M. Sharma, SPE, U. of Texas at Austin, originally presented at the 2001 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September- 3 October.
Overview: Reservoir Visualization (February 2002)
Authors: Keach R. William
Published: February 2015

Overview - No abstract available.
Visualization: Game Changer, Facilitator, or Gimmick?
Authors: Denney Dennis
Published: February 2015

This article is a synopsis of paper SPE 67754, "Visualization: Game Changer, Facilitator, or Gimmick?," by W. Wright, SPE, Schlumberger; J. Holt, SPE, BP; I. Rezmer-Cooper, SPE, Schlumberger; R. Minton, SPE, BP; and C. Ramshorn, Schlumberger, originally presented at the 2001 SPE/IADC Drilling Conference, Amsterdam, 27 February-1 March.
Injectivity Tests on Horizontal Wells
Authors: Bybee Karen
Published: February 2015

This article is a synopsis of paper SPE 71582, "Theory and Analysis of Injectivity Tests on Horizontal Wells," by Alvaro M.M. Peres, SPE, Petrobras, and Albert C. Reynolds, SPE, U. of Tulsa, originally presented at the 2001 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September- 3 October.
The Need for a New Drilling Engineering Textbook
Authors: Thorogood John
Published: February 2015

Guest editorial - No abstract available.
Visualization - Does It Make a Difference?
Authors: Giertsen Christopher
Published: February 2015

Management - No abstract available.
Overview: Drilling Technology (February 2003)
Authors: Kerbart Yves
Published: February 2015

Overview - No abstract available.
The Monodiameter Well: - Evolution of a Game-Changing Technology
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 14312, "Realization of the Monodiameter Well: Evolution of a Game-Changing Technology," by Kenneth Dupal, SPE, Shell Deepwater Development Inc.; Donald B. Campo, SPE, Shell Intl. E&P; Colley J. Andrews, SPE, Chesapeake Energy Corp.; and Lance Cook, SPE, Lev M. Ring, SPE, and Patrick L. York, SPE, Enventure Global Technology, originally presented at the 2002 Offshore Technology Conference, Houston, 6-9 May.
Assessment and Modeling of High-Permeability Areas in Carbonate Reservoirs
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 77591, "Assessment and Modeling of High- Permeability Areas in Carbonate Reservoirs," by G. Massonnat, SPE, and E. Pernarcic, TotalFinaElf, originally presented at the 2002 SPE Annual Technical Conference and Exhibition, Dallas, 29 September- 2 October.
Injection Tests for Reservoir Appraisals
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 77454, "Application of Injection Tests for Reservoir Appraisals: A Conceptual Study," by Ronald G. Gan, Vico Indonesia; Nal-Shyong Yeh, BP Egypt (Gupco); and Curtis O. Bennett, BP plc, originally presented at the 2002 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 29 September-2 October.
Stand Tall and Speak Up: Natural Gas - Image vs. Reality
Authors: Sprunt Eve S.
Published: February 2015

We often lump oil and natural gas together, but in many ways they are very different products, which are used in different applications. While those of us in the petroleum industry view natural gas as an excellent, environmentally friendly energy alternative, our potential customers do not necessarily share that perspective. In some markets, natural gas has a bad image.

From our perspective, natural gas is the most environmentally friendly fossil fuel and as such an excellent source of energy for electric power generation. Combustion of natural gas emits almost 30% less carbon dioxide than oil and about 45% less carbon dioxide than coal; virtually no sulfur dioxide; and up to 80% fewer nitrogen oxides than coal. Emissions of particulates from natural gas combustion are negligible. With all these advantages, we believe that customers should have a strong preference for natural gas. Nevertheless, electric utilities often see natural gas as an interim fix, with the long-term solution being clean coal technology.

Many countries still depend on coal for power generation even though combustion of coal emits larger amounts of pollutants than alternatives. In the U.S., coal is used to generate 51% of the nation's electrical power. Natural gas is a distant third at about 17%, behind nuclear power with a 21% market share. Some other nations are even more dependent on coal-fired electrical generation. Poland is 97% coal dependent, while India is 78%, China 76%, and Australia 70%.

Electrical generation facilities using efficient, natural gas-fired combustion turbine technology can be completed in far less time and with far less capital than other technologies. However, even as utilities are building gas-fired plants, they are looking to clean coal technologies as the preferred next-generation solution. This is reflected in the U.S. Energy Information Administration's Annual Energy Outlook 2005, which predicts that in the long term most new electric power plants will use clean coal technology rather than natural gas (Fig. 1).

In a modern natural-gas-fired power plant, fuel accounts for almost 90% of the operating costs. In the last couple of years, U.S. natural gas prices have more than tripled (Fig. 2), reinforcing utilities' concerns about price volatility.

When we look at natural gas, we see opportunities in the high prices and regional scarcity. With rising natural gas prices in North America and increasing demand in China, LNG projects have become some of the hottest games in town. Everyone is competing to sell LNG and build LNG terminals. Unfortunately, like so many other aspects of the oil industry, what is viewed as good for us is viewed as bad by the general public and our customers.
Deconvolution of Variable-Rate Reservoir-Performance Data Using B-Splines
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 95571, "Deconvolution of Variable- Rate Reservoir-Performance Data Using B-Splines," by D. Ilk, P.P. Valko, SPE, and T.A. Blasingame, SPE, Texas A&M U., prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October.

This work presents the development, validation, and application of a deconvolution method that uses B-splines to analyze variable-rate reservoir-performance data. Variable-rate deconvolution is a mathematically unstable problem. B-splines represent the derivative of unknown unit-rate drawdown pressure, and numerical inversion of the Laplace transform is used in this formulation. When significant errors and inconsistencies exist in the data functions, direct and indirect regularization methods are used (i.e., mathematical "uniformity" processes). The new deconvolution method has broad applicability in variable-rate/pressure problems and can be implemented in typical well-test and production data analysis.

Deconvolution

The constant-rate drawdown-pressure behavior of a well/reservoir system is the primary signature used to classify/establish the characteristic reservoir model. Transient-well-test procedures typically are designed to create a pair of controlled flow periods (a pressure-drawdown/-buildup sequence) and to convert the last part of the response (the pressure buildup) into an equivalent constant-rate drawdown by use of special time transforms. However, the presence of wellbore storage, previous flow history, and rate variations may mask or distort characteristic features in the pressure and rate responses.

With accurate downhole data, the variable-rate deconvolution should be viable for traditional well-test methods because deconvolution can provide an equivalent constant-rate response for the entire time span of observation.

Variable-rate deconvolution is mathematically ill-conditioned. While many methods are applied to deconvolve ideal data, very few deconvolution methods perform well in practice. The ill-conditioned nature of the deconvolution problem means that small changes in the input data cause large variations in the deconvolved constant-rate pressures. Mathematically, this method attempts to solve a first-kind Volterra equation, which is ill-posed. However, in this case, the kernel of the Volterra-type equation is the flow-rate function (i.e., the generating function), which is not known analytically but approximated from the observed flow rates, adding to the complexity of the problem.
Overview: Well Testing (February 2007)
Authors: Stratton Jay
Published: February 2015

In some of the oil and gas industry's most demanding field developments, engineers can spend months preparing a test program for a deepwater subsea completion that could cost millions of dollars to execute. Other innovative operators are able to convince management of the benefit to drilling horizontal wells to determine pressure profiles through a prolific, yet complicated, reservoir. Conversely, in marginal fields, many wells may not have been tested for years and may never be tested before they are disposed of in the next asset sale.

Clearly, opportunity, mitigating risk in frontier areas, lack of technical resources, and other justifications play a role in the frequency and type of well-testing operations that an engineer will recommend. In my own experience, it can be difficult to convince operations personnel that a good testing program can increase production by identifying underperforming wells for remedial programs or more nearly optimum operating practices. Our role as engineers is to use our education, judgment, and experience to make decisions that provide the highest-value information at the lowest possible cost to our project. The SPE technical-paper library provides a great resource of where this has been done by some of our industry's top technical people.

The papers reviewed for this month's well-testing feature were some of the most interesting and varied in the time I have been on the JPT Editorial Committee. There were many more technical papers I could have chosen this year that offer real applicability to the practicing field engineer and just as many that would interest those doing research. The papers that were selected represent progress in areas of well-test interpretation that have been problematic in the past. There also are reviews of advanced well-test-interpretation methods that should be a great resource to many. Also discussed are new ways of applying well-development technology to answer questions about optimizing an entire field's development plan.

I would encourage anyone with the slightest interest in well testing to do a thorough literature search to take advantage of the many well-written papers on a broad variety of well-testing topics that have been published this year. Even in our robust and high-oil-price environment, we find persistent pressure to do more with less. I found the technical papers reviewed this year to be of very practical interest to the well-test designer and interpreter interested in maximizing the information that can be extracted from well testing. Good reading.

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

SPE 103222 "Rate Allocation Using Permanent Downhole Pressures" by M. McCracken, SPE, ExxonMobil Upstream Research, et al.

SPE 103040 "A Digital Pressure-Derivative Technique for Pressure Transient Well Testing and Reservoir Characterization" by A.F. Veneruso, SPE, Schlumberger, et al.

SPE 102079 "From Straight Lines to Deconvolution: The Evolution of the State of the Art in Well-Test Analysis" by A.C. Gringarten, SPE, Imperial College, London.
Coiled Tubing "Vacuum" Restores North Slope Wells
Authors: JPT staff _
Published: February 2015

Technology Update

The North Slope of Alaska is home to thousands of oil wells, most drilled horizontally and then stimulated with hydraulic fracturing or allowed to flow through natural formation fractures. Wellbore plugging caused by proppant flowback and formation fines can be a problem in these wells, with severe impact on production.

For most of these wells, conventional coiled-tubing (CT) cleanouts are possible, using nitrogen to lift the cleaning fluid and suspended proppant to surface. Some of these wells, however, are so underpressured that normal CT cleanouts are technically and/or economically unfeasible because of the massive amounts of nitrogen required to achieve returns to the surface.

A Vacuum Cleanout Method

One alternative is to clean out the fill by means of concentric coiled tubing (CCT) with a downhole-vacuum tool. The BJ Services Sand-Vac cleanout tool is based on a jet pump comprising a high-pressure nozzle, suction port, and diffuser (Fig. 1). High-pressure fluid is accelerated through the nozzle, creating a pressure drop that essentially draws in wellbore fluids, jetted fluids, and suspended solids. A diffuser allows the velocity of the combined flow to decrease and the pressure to increase. This pressure gain is sufficient to drive the column of return fluids back to the surface.

To run the jet pump, power fluid is pumped down the center of a CCT string, with a portion of the fluid allowed to exit an external nozzle to fluidize wellbore solids. Returns come up the larger annulus between the inner and outer strings. Because the CCT string provides the additional flow path, the wellbore is not exposed to the return pressure and, therefore, nitrogen is not required. All of the supplied fluid is returned to the surface, leaving none in the well.

This technology was born in the Canadian heavy-oil fields, and it has been proved in a decade of cleanouts around the world—especially in low-pressure, horizontal wells and in areas where nitrogen logistics are difficult or simply too expensive to justify.

Alaska Gas Wells

In 2006, for example, this technology was employed on the Tyonek platform in the Cook Inlet basin in southern Alaska (Rafferty et al. 2007). This platform ties together 14 wells that produce from the Cook Inlet and Beluga reservoirs, which have bottomhole-pressure (BHP) gradients of less than 0.1 psi/ft.

Both reservoirs are composed of highly permeable, friable sandstones that tend to slump into unconsolidated sand piles upon exposure to water. Water breakthrough, therefore, creates major sand-production problems for wells in this area.
Better, Smarter Rig Design Developed for Alaska's North Slope
Authors: Wallace Rhea
Published: February 2015

Technology Update - No abstract available.
New Treatments Increase LOT/FIT Pressures
Authors: Bybee Karen
Published: February 2015

This article is a synopsis of paper SPE 71390, "New Treatments Substantially Increase LOT/FIT Pressures to Solve Deep HTHP Drilling Challenges," by Sid Webb, SPE, and Tom Anderson, Berkley Petroleum Inc., and Ron Sweatman, SPE, and Richard Vargo, SPE, Halliburton Energy Services Inc., originally presented at the 2001 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-3 October.
Completion Design for an HP/HT Well in California
Authors: Bybee Karen
Published: February 2015

This article is a synopsis of paper SPE 71684, "Completion Design and Implementation in Challenging, Extreme HP/HT Wells in California," by D.E. Hahn, SPE, L.H. Burke, SPE, and S.F. Mackenzie, SPE, Adams Pearson Assocs. Inc., and K.H. Archibald, SPE, Anadarko Canada Corp., originally presented at the 2001 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September- 3 October.
Overview: Hydraulic Fracturing (March 2002)
Authors: Britt Larry K.
Published: February 2015

Overview - No abstract available.
Hydraulic Fracturing for Reservoir ManagementHydraulic Fracturing for Reservoir Management
Authors: Denney Dennis
Published: February 2015

This article is a synopsis of paper SPE 71655, "Hydraulic Fracturing for Reservoir Management: Production Enhancement, Scale Control, and Asphaltine Prevention," by M.R. Norris, S.N. Gulrajani, and A.K. Mathur, Schlumberger; J. Price and D. May, Amerada Hess, originally presented at the 2001 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-3 October.
Mitigation of Wellbore Solids Deposits
Authors: Bybee Karen
Published: February 2015

This article is a synopsis of paper SPE 71558, "An Approach to Mitigating Wellbore Solids Deposition," by C.S. Kabir, SPE, Chevron Overseas Petroleum Inc.; A.R. Hasan, SPE, and D. Lin, U. of North Dakota; and X. Wang, TRW, originally presented at the 2001 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-3 October.
Static/Dynamic Evaluation of Calcium Carbonate Scale Formation and Inhibition
Authors: Denney Dennis
Published: February 2015

This article is a synopsis of paper SPE 68963, "Static and Dynamic Evaluation of Calcium Carbonate Scale Formation and Inhibition," by N. Kohler, SPE, G. Courbin, and F. Ropital, Inst. Francais du Petrole, originally presented at the 2001 SPE European Formation Damage Conference, The Hague, 21-22 May.
Comments (March 2003)
Authors: Donnelly John
Published: February 2015

Editor's column - No abstract available.
Overview: Hydraulic Fracturing (March 2003)
Authors: Hellman Tom
Published: February 2015

Overview - No abstract available.
Hydraulic Fracturing in the Ghawar Field Carbonate and Sandstone Reservoirs
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 77677, "Hydraulic Fracturing Case Histories in the Carbonate and Sandstone Reservoirs of Khuff and PreKhuff Formations, Ghawar Field, Saudi Arabia," by Zillur Rahim, Kirk Bartko, SPE, and Mohammed Y. Al-Qahtani, SPE, Saudi Aramco, originally presented at the 2002 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 29 September-2 October.
Equilibrium Test: Determining Closure Pressure
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 78173, "Equilibrium Test - A Method for Closure Pressure Determination," by X. Weng, SPE, V. Pandey, SPE, and K.G. Nolte, SPE, Schlumberger, originally presented at the 2002 SPE/ISRM Rock Mechanics Conference, Irving, Texas, 20-23 October.
Insights Into Water Control: A Review
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 79012, "New Insights Into Water Control: A Review of the State of the Art - Part 2," by Gino Di Lullo, SPE, Phil Rae, SPE, and James Curtis, SPE, BJ Services, originally presented at the 2002 SPE/PS-CIM/CHOA International Thermal Operations and Heavy Oil Symposium and International Horizontal Well Technology Conference, Calgary, 4-7 November.
Drilling HP/HT Wells in Bosque Field, Venezuela
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 79815, "Drilling HP/HT Wells in Bosque Field, Venezuela - The Aloctono Block Challenge," by J.C. Avila, SPE, E. Zerpa, L. Rojas, and J.G. Salas, SPE, Petroleos de Venezuela, S. A., originally prepared for presentation at the 2003 SPE/IADC Drilling Conference, Amsterdam, 19-21 February.
Assessment of Several Sand Prediction Models
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 78235, "Assessment of Several Sand Prediction Models With Particular Reference to HP/HT Wells," by Hans Vaziri, SPE, BP America Inc.; Yuing Xiao, Dalhousie U.; and Ian Palmer, SPE, BP America Inc., originally presented at the 2002 SPE/ISRM Rock Mechanics Conference, Irving, Texas, 20-23 October.
Overview: Hydraulic Fracturing (March 2005)
Authors: Hellman Tom
Published: February 2015

To stay informed with the latest advancements in fracturing technology, we continually search publications for useful theories or look for relevant case studies that apply new models or methods. We find that the tools and diagnostics available are impressive and gaining in sophistication: frac models that are fully 3D, reservoir simulators that include non-Darcy effects, and improved microseismic interpretation are recent favorites. Also impressive are the advancements in isolation techniques, reducing the time between staging of fracture treatments and flowback. Now, 12 separate stages along a vertical well is commonplace, not to mention staging multiple fracture treatments along horizontal wells.

For those new to fracturing, with plans on becoming “informed buyers” of fracture technology, the complexity of the models and diagnostics may appear overwhelming. Fortunately, the tools of the trade are becoming more user-friendly, more visual, and more intuitive. A truly sophisticated frac model is technically superior, and it is becoming simpler to learn and use correctly. Like many engineering software applications, frac models typically added functionality at the expense of complicating the user interface. Thankfully, this trend appears to be reversing, and this is good news because our future success in optimizing fracture treatments will, at least in part, depend on our willingness to experiment and master them.

However, it is slightly ironic that, even now, with 3D numerical models and microseismic-data interpretation at our fingertips, possibly our most powerful tool is a human trait—good old-fashioned curiosity. It drives us to keep searching for better answers to the fundamental questions. It raises our expectations. And from this year’s publications, it is evident that vendors and operators are finding better solutions to some of the most fundamental questions.

Maybe there is a lesson here for those new or returning to fracturing. One does not have to be an “expert” to be a major contributor; we just need to keep asking questions—the answers seem to keep getting better and better.

Additional Hydraulic Fracturing Technical Papers

Available at the SPE eLibrary: www.spe.org

SPE 90357 - Pushing the Limits of Hydraulic Fracturing in Russia

SPE 89875 - Modeling Proppant Settling in Waterfracs

SPE 90406 - Multiphase Non-Darcy Pressure Drop in Hydraulic Fracturing

SPE 90864 - An Investigation of Non-Darcy-Flow Effects on Hydraulically Fractured Oil- and Gas-Well Performance
Overview: HP/HT Challenges (March 2005)
Authors: MacAndrew Robert
Published: February 2015

It is quite a thought when those of us who have been in this industry for more years than we perhaps care to count take a few moments to look back and reflect on the progress made in drilling and completing high-pressure/high-temperature (HP/HT) wells over the years. It is easy to for-get that oil-based mud was developed to answer the problem of high-temperature wells. It was only when oil-based mud’s inhibitive properties MacAndrew in reactive clays were recognized that it became common in more-prosaic “normal” wells where the time savings made the higher cost of the oil-based mud economical and, in many places, changed the drilling of wells out of all recognition when compared with drilling with water-based mud. I am sure there are some reading this who can remember the original diesel-based muds. Just as in the case of mud, the demands of high operating pressures and temperatures drove our industry to develop higher specifications and manufacturing standards for equipment that have provided benefit to the rest of the industry.

Now, we are pushing to drill HP/HT wells in water depths that push boundaries ever further. Today, we are drilling HP/HT wells for which, aside from drilling the HP/HT section, drilling the non-HP/HT section often is a significant challenge in itself. In the Gulf of Mexico deep-gas shelf play, well depths of more than 30,000 ft, pore-pressure regimes of 30,000 psi, and bottomhole temperatures of 500°F are actively contemplated. These sorts of plays are stretching technology as much as, if not more than, the first HP/HT wells did. Our industry is taking on the challenge of not only drilling these new “super” wells, but also finding the materials to complete them and produce the hydrocarbons. The oil and gas industry may be seen by many as a mature one; but taking on the new challenges of HP/HT wells makes it just as exciting as any of the newer, more-fashionable industries.

There is life in the old dog yet!

Additional HP/HT Challenges Technical Papers

Available at the SPE eLibrary: www.spe.org

SPE 87094 - Numerical Models Help Analyze Lost-Circulation/Flow Events and Frac-Gradient Increase to Control an HP/HT Well in the Eastern Mediterranean Sea

SPE 92218 - Jade North Sea HP/HT Development: Innovative Well Design Generates Best-In-Class Performance

SPE 92003 - Reservoir Simulations of Gel Treatments To Control Water Production Improve the Sweep Efficiency and Conformance Factor in Eastern Venezuelan HP/HT Fractured Reservoirs
Overview: HP/HT Challenges (March 2007)
Authors: MacAndrew Robert
Published: February 2015

It has been quite an enlightening experience reviewing potential papers for this issue of JPT. Over time, there has been a steady geographic spread of high-pressure/high-temperature (HP/HT) activity, which is reflected in the papers the Society is publishing. Papers are being presented at conferences around the world. The geographic area has expanded, issues being addressed at these conferences are widening, and our industry is addressing the challenges being presented by drilling, completing, and producing from HP/HT reservoirs. A body of experience in operating HP/HT developments is being built up, and through SPE, these experiences are being disseminated throughout the industry.

We now have HP/HT wells being split into three categories based on the temperature and pressure envelopes, namely Tier 1 (HP/HT), Tier 2 (extreme HP/HT), and Tier 3 (ultra-HP/HT). Ultra-HP/HT wells, with temperature higher than 400°F and pressure greater than 20,000 psi, are being planned, and this work is highlighting the current limitations in available technology in many areas. At the upper limits of Tier-2 wells (i.e., pressure of 20,000 psi and temperature of 400°F), we generally are at the limits of current technology, and there are such serious technological gaps that completing these wells currently is beyond our capabilities. All is not gloom and doom; the service sector is seriously investigating future equipment developments to meet the demands of these wells.

Some service companies are working under their own initiative, and at least one commercial joint-industry research and testing venture is being proposed to the industry. The big question is: Can the industry apply the necessary resources of people and money in time to prevent a stalling of ultra-HP/HT developments?

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

SPE 99968 "New Downhole Electromechanical-Service-Tool Advancements Provide Increased Integrity in HP/HT Environments" by J. Foster, Halliburton Energy Services Group, et al.

SPE 98869 "Finite-Element Analysis Couples Casing and Cement Designs for HP/HT Wells in East Texas" by J. Heathman, SPE, Halliburton, et al.

SPE 98896 "Effects of Long-Term Exposure to Ultrahigh Temperature on the Mechanical Parameters of Cement" by D. Stiles, SPE, ExxonMobil Development Co.
Offshore Gas-to-Solids Technology
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 71805, "Offshore Gas-to-Solids Technology," by Antony Fitzgerald, BG Group, originally presented at the 2001 SPE Offshore Europe Conference, Aberdeen, 4-7 September.
Engineering Considerations of Development of a Deepwater Biogenic Gas Accumulation
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 71611, "Mississippi Canyon 348: Some Reservoir Engineering Considerations Regarding Development of a Deepwater Biogenic Gas Accumulation," by J.D. Edman, Geomark Research Inc., and E.W. Jameson, T.M. Perkins, and G.E. Guthrie, Marathon, originally presented at the 2001 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-3 October.
Reeled Pipe-in-Pipe Steel Catenary Riser
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 13184, "Reeled PIP SCR," by Mike Bell and Roland Daly, Coflexip Stena Offshore, originally presented at the 2001 Offshore Technology Conference, Houston, 30 April-3 May.
Overview: Natural Gas Technology (April 2002)
Authors: Jones Jack R.
Published: February 2015

Overview - No abstract available.
Enhanced Shaly Sand Reservoir Characterization
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 71724, "Field Example Demonstrating a Significant Increase in Calculated Gas-In-Place: An Enhanced Shaly Sand Reservoir Characterization Model Utilizing 3DEX Multicomponent Induction Data," By Geoffrey C. Page, SPE, Otto N. Fanini, SPE, Berthold F. Kriegshäuser, SPE, Richard A. Mollison, SPE, and Liming Yu, Baker Atlas, and Nick Colley, SPE, BG Energy Holdings Ltd., originally presented at the 2001 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September- 3 October.
Modeling Fracture Propagation Induced by Water Injection/Reinjection
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 68974, "Numerical Modeling of Fracture Propagation Induced by Water Injection/Re- Injection," by P. Longuemare, Institut Francais du Petrole, J.-L. Detienne, TotalFinaElf, P. Lemonnier, Institut Francais du Petrole, M. Bouteca, Institut Francais du Petrole, and A. Onaisi, TotalFinaElf, originally presented at the 2001 SPE European Formation Damage Conference, The Hague, 21-22 May.
Comments (April 2003)
Authors: Donnelly John
Published: February 2015

Editor's column - No abstract available.
Why Oil Terrorism, and Why Managers Should Care
Authors: Adams Neal
Published: February 2015

Guest editorial - No abstract available.
Expandable Screen Provides Increased Sand Control, Production
Authors: Wallace Rhea
Published: February 2015

Technology Update - No abstract available.
Deepwater Development Environmental Issues and Challenges
Authors: Armstrong Louis J. , Puz Gabrielle , Jean Philippe
Published: February 2015

HSE Horizons - This is a condensed version of paper SPE 73873, which was presented at the SPE International Conference on Health, Safety, and Environment in Oil and Gas E&P held in Kuala Lumpur, Malaysia, 20-22 March 2002.
Overview: Offshore E&P (April 2003)
Authors: Tollefsen Svein
Published: February 2015

Overview - No abstract available.
World-Class Drilling in the Gulf of Thailand
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 79896, "World- Class Drilling in the Gulf of Thailand: North Pailin Project," by Wiwat Yodinlom, SPE, Nat Luckanakul, and Pichai Tanamaitreejitt, Unocal Thailand Ltd., originally presented at the 2003 SPE/IADC Drilling Conference, Amsterdam, 19-21 February.
Overview: Natural Gas Technology (April 2003)
Authors: Jones Jack R.
Published: February 2015

Overview - No abstract available.
Two Low-Dosage Hydrate Inhibitors
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 75668, "Hydrate Inhibition in Gas Wells Treated With Two Low-Dosage Hydrate Inhibitors," by Dean Lovell, ConocoPhillips Canada and Marek Pakulski, SPE, BJ Unichem Chemical Services, originally presented at the 2002 SPE Gas Technology Symposium, Calgary, 30 April- 2 May.
Experiences With Automated History Matching
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 79670, "Experiences With Automated History Matching," by C.S. Kabir, SPE, ChevronTexaco Overseas Petroleum, M.C.H. Chien, SPE, Focus Simulation Inc., and J.L. Landa, SPE, ChevronTexaco EPTC, originally presented at the 2003 SPE Reservoir Simulation Symposium, Houston, 3-5 February.
The Quadruple Bottom Line (April 2004)
Authors: Baker Kate H.
Published: February 2015

President's column - No abstract available.
Managing the Tradeoffs: Similarities Between Managing New Product Development and a Well Drilling/Completion Project
Authors: Shaw B.S. , Morris T.G.
Published: February 2015

As stated by Smith and Reinertsen in Developing Products in Half the Time, “managing the tradeoffs” should be a primary consideration when planning and executing a development project. Managing the tradeoffs means being aware of four major project objectives inherent in all development projects and actively managing the six potential interactions between these four objectives. This technique provides the project execution team with tools that, when applied consistently, ensure optimized project/product delivery within a win-win atmosphere. This technique can work as well for a drilling/completion project as it does for new product development projects.

Cross-Functional Teams

The concept of establishing co-located, cross-functional project execution teams for both new product development and for oil- and gasfield development is well established. These teams are most effective when they are:

- Led by a competent and committed project manager with full management support.

- Empowered to make value-added decisions on behalf of the project and the company.

- Aligned with a common set of goals and rewards.

- Allowed to define their own work processes and encouraged to build team spirit.

- Held accountable to clear and realistic targets.

- Provided with the best training, tools, and technical support available.

For developments that rely on suppliers for delivery of critical equipment, services, and technology, an important element of success is to include a technical representative from each major supplier. Additionally, a well-constructed development process, such as a stages-and-gates (or “toll-gate”) process, helps the team break the work into manageable pieces and to focus on the deliverables that will lead to success at the next step of the project.
Overview: Reservoir Simulation (April 2003)
Authors: May Ed
Published: February 2015

Overview - No abstract available.
Technology Focus: Offshore Drilling and Completion (April 2008)
Authors: Jousseaume Jean-Louis
Published: February 2015

Technology Focus

I do not yet consider myself an old-timer. However, I remember when I started studying petroleum engineering; our teacher was telling us that drilling was a technology that had not progressed in years, not since its last revolution—the introduction of rotary drilling. The word "revolution" here definitely seems the right one.

Since those days, we have seen the introduction of new technologies, such as measurement while drilling, steerable systems, top drives, more-reliable dynamic-positioning systems, dual handling, smart completions, new equipment, new chemicals, new metallurgy, and an exhaustive list of others. These advances enabled success of wells that were increasingly difficult, and we now are drilling horizontally (again, I remember: "It is impossible to drill horizontally, because it is impossible to transmit weight on bit horizontally") and underbalanced, we are drilling high-pressure/high-temperature (and soon very-high-pressure/very-high-temperature) reservoirs and in deep and ultradeep waters, and we are drilling slim or ultraslim wellbores, multilateral and extended-reach wellbores, and combinations of these. Future wellbores will be even more exotic.

We complete wells with smart technology or sophisticated multilateral connections, produce gas from tight or ultratight sands, and heat silts in-situ to produce heavy bitumen. Simultaneously, we are making tremendous progress to protect people from incidents and diseases and our environment from unbearable or irreversible damages, especially when using nonaqueous-based mud.

Again, this list of recent advances is not complete, but it gives the strong feeling that all of us are engineers dealing with a moving and expanding technology. Actually, it gives me the strong belief that we will overcome new challenges and that, peak oil or not (whenever it may happen), there still is a lot to engineer, a lot to invent, and a lot to progress to move the limits of feasibility in drilling and well engineering further and further.

Offshore Drilling and Completion additional reading available at the SPE eLibrary: www.spe.org

SPE 105212 • "Deployment of a Riserless Mud-Recovery System Offshore Sakhalin Island" by J.D. Brown, CJSC Elvary Neftegaz, et al.

SPE 110359 • "Subsea Slimhole Completions in Deepwater Gulf of Mexico: Case Histories" by J.R. Sanford, Eni Petroleum, et al.

Additional reading available at the OTC Library: www.otcnet.org

OTC 19077 • "First Jackup Drilling Operation on Grand Banks of Newfoundland—Lessons Learned" by G.C. Bagnell, Rowan Companies

OTC 18496 • "2-Million-lbm Slip-Based Landing-String System Pushes the Limit of Deepwater Casing Running" by James N. Brock, Grant Prideco, et al.
Gumusut-Kakap Project: Geohazard Characterization and Effect on Field Development
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 12554, "Gumusut-Kakap Project: Geohazard Characterisation and Impact on Field- Development Plans," by C. Hadley, D. Peters, and A. Vaughan, SPE, Shell International E&P, and D. Bean, Sarawak Shell Sdn. Bhd., originally prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3-5 December. The paper has not been peer reviewed.

Shell and venture partners encountered numerous seafloor and near-seafloor geohazards at the deepwater Gumusut-Kakap field on the continental slope offshore Malaysia. Early identification of the geohazards, by interpretation of exploration 3D-seismic data and evaluation of discovery and appraisal-well logs, provided the impetus necessary to undertake an extensive data-acquisition program to determine the extent of the hazards and the mitigation needed for a successful development.

Introduction

The Gumusut-Kakap field in the Malaysian deepwater province offshore northwest Borneo was discovered in 2003 with the drilling of the Gumusut-1B well. The field is 120 km offshore, in the southern portion of Sabah Block J and Block K. Four appraisal wells, Gumusut-2 and Gumusut-3 in Block J and Kakap-1 and Kakap-2 in Block K, were drilled during 2004–05.

The seafloor slopes regionally to the southwest, with a gradient of approximately 5°, and water depths within the development area vary from 900 to 1200 m. Seafloor and near-seafloor sediments are hemipelagic, interbedded with turbidites and mass-transport deposits (MTDs). Exploration 3D-seismic data and data from the discovery and appraisal wells were interpreted in 2005 to identify geohazards that could influence field-development plans and to screen potential surface well locations.

The seafloor extraction from the 3D-seismic data set revealed a variable seafloor topography. The most prominent topographic features are a series of upper-slope canyons, which are interpreted to be the seafloor expression of buried mass-transport complexes and a steep-sided seafloor bulge. The bulge rises 120 to 150 m above the surrounding seafloor and is approximately 8 km wide. The bulge is the surface expression of one of a series of deep-seated anticlines, which are common in the region. Both flanks of the bulge have been eroded by downslope mass failures. Appraisal wells Gumusut-2, Kakap-1, and Kakap-2 were drilled on the bulge.

Anomalies in the subsurface data included a bottom-simulating reflector (BSR) between 150 and 180 m below the seafloor, which underlies the downdip portion of the bulge and coincides with an extensive seismic wipeout zone.
Is Your Company Right or Enron-g?
Authors: Koerner Roy H.
Published: February 2015

Guest editorial - No abstract available.
To Straddle or Not To Straddle - The Inflatable Option
Authors: Mackenzie Gordon R.J.
Published: February 2015

Technology Update - No abstract available.
New People, New Rig: Managing Performance
Authors: Blank Bob
Published: February 2015

Management - This is a condensed version of SPE 74477, which was prepared for presentation at the SPE/IADC Drilling Conference held in Dallas, 26-28 February 2002.
Slip Crushing Considerations for Deepwater Drilling
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 74488, "Advanced Slip Crushing Considerations for Deepwater Drilling," by U.B. Sathuvalli, SPE, Blade Energy Partners; M.L. Payne, SPE, BP; P.V. Suryanarayana, SPE, Blade Energy Partners; and J. Shepard, Global-SantaFe, originally presented at the 2002 IADC/SPE Drilling Conference, Dallas, 26-28 February.