bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gaining Commitment to Large and Complex Internal Projects
Authors: Floyd Peter 
Published: February 2015

Management
Every journey begins with one small, first step. You have probably heard that phrase or one like it before. Yet, quite often—and counter-intuitively—the second step is actually more difficult than the first.
We have all had that moment (that first step) where a fantastic idea or solution to a problem pops into our head from nowhere. Then we go and talk enthusiastically about it with our colleagues (that second step), often to be met with a disappointing and less than positive response. Dejected, we retreat back into our inner world, bemoaning the people we work with and also possibly the organization.
This scenario has strong parallels in the world of project proposals, where exactly the same process, and outcome, is regularly experienced. This is particularly true when considering the large-scale, strategic, and organizational-focused issues such as implementing processes around the big crew change, standardization, integration, or the implementation of new computer technologies. These types of project have a number of unique characteristics, when compared to more technical projects, which make the commitment-gaining process considerably more difficult.
So the big question for people wanting to get an idea off the ground is, "How do I effectively initiate and gain commitment to such ideas and projects?" This article provides some answers and strategies for this challenge, which centers on a missing step—walking in other people's shoes.

Lower-Profile Projects
The oil and gas industry faces an increasingly wide range of technical challenges that are widely known and documented. These technical and capital projects are seen as the glamorous side of the business, typically at the cutting edge of technology, which after all, is what has made this industry successful. Hence, these projects are usually given greater prominence. But what about the more internal and organizational-related projects? These usually have a lower profile, and dare to say, often a lower success rate. Are these types of projects as important and challenging as the technical ones?
Important? Absolutely. Many of the strategic issues facing the industry are as much organizational as technical. Organizational productivity, efficiency, and effectiveness are becoming increasingly important and urgent topics within our industry. And the means of achieving these goals—standardization, integration, optimization, and leveraging the functionality of technology—are affected as well.
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.
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.
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