bluuebunny/crossref_metadata_2025_split huggingface dataset:
Overview: Well Testing (February 2008)
Authors: Stratton Jay 
Published: February 2015

Overview
Well-testing papers under review for this feature become more numerous and varied each year. Consequently, this issue's papers represent a cross section of only some of the varied resource-development conditions under which industry professionals are designing and evaluating wells to determine productivity and reservoir parameters. The analysis of pressure data with accurate rate information is the root of petroleum engineering calculations.
Whether your need for measurement accuracy and resolution is a fraction of a psi for interference testing or hundreds of psi for qualitative depletion information on an infill-drilling project, knowledge of pressure is still fundamental.
The first paper describes the approach one operator is pursuing to refine their knowledge of one of the largest tight gas resources in the USA. Described are the constraints, challenges, and ultimate solutions they developed in pursuit of optimizing the recovery of this significant resource. The second paper provides a good example how integrating well-test design and analysis with existing geologic- and reservoir-description information enhances the accuracy of the final results. The third paper provides insight into the detailed planning and preparation that go into a successful well test and shares the post-job analysis comparing the actual test results with the original objectives. I am always amazed at the considerable planning and expense that go into oil/gas recommendations and operations that still lack any priority for capturing important (and relatively inexpensive) results for reference and optimization. This paper is a good read for anyone wanting an appreciation of the issues to be considered for well testing in challenging environments.
Many more good papers were reviewed than could be mentioned in this feature. The three selections listed for additional reading give us insight into the challenges faced and solutions implemented by service companies and operators to solve testing and interpretation needs in areas such as pressure testing while drilling, non-Darcy-flow modeling, and fracture properties of naturally fractured reservoirs.
The SPE eLibrary is a valuable resource that I encourage all to search for additional papers in your area of interest within the far-reaching topic of well testing.
Well Testing additional reading available at the SPE eLibrary: www.spe.org
SPE 103803 "Formation-Pressure Testing While Drilling in Bohai Bay's Challenging Environment" by Ulrich Hahne, SPE, Baker Hughes Inteq, et al.
SPE 107853 "Modeling Non-Darcy Flow and Perforation Convergence for Vertically Fractured Wells" by H. Huang, SPE, Georgia Institute of Technology, et al.
SPE 107418 "Effects of Stress on Fracture Properties of Naturally Fractured Reservoirs" by Abel Chacon, SPE, BP plc, et al.
Your SPE: Global Economic Crisis - Challenges for Industry and for SPE
Authors: Roodhart Leo 
Published: February 2015

President's column
In my columns up to now, I have completely ignored the fact that the world is in an economic crisis at the moment. This is not because I travel around so much that I don't realize there is something going on. The simplest reason is that my column has to be completed more than 2 months before you read it because of publishing deadlines. The second reason is that SPE is a professional society that offers a forum for like-minded individuals in which an exchange of technical ideas and information can take place. In different words, we are not a lobbying organization and we do not do politics.
However, we are, as a society, part of the greater world and any crises, such as the current one, will affect SPE's operations. During the 50+ years of our existence, SPE has survived crises of all kinds, so I do not worry too much. SPE is financially very robust, with a good reserve fund built up during the last decade of growth and good support from members and organizations. However, everything SPE does is around oil and gas and that means that anything that affects oil prices will affect SPE.
So, what's going on? The oil market is inherently volatile; it has made a fool out of forecasters many times over the last decades, and it will make a fool out of me if I would even try to predict what will happen in 2009. On the one hand, we are made to believe that the current economic recession will end the growth in oil/energy use, which means that even if the supply growth slows, the extra production will not be needed and oil prices go down. Against that short-term view, there are a number of thinkers from our own industry, who I will cite here, who argue that our industry requires a long-term view. Analysis from sources such as Simmons & Company Intl., Douglas-Westwood, and the Paris-based energy think tank International Energy Agency (IEA) can be found on their web sites.
What they are saying is that, at the moment, many of the world's economies are still robust. The economies of India, China, and the Middle East are still growing, and China has a USD 1.9 trillion cash war chest. Of course, the financial crisis could spread into a serious economic downturn (and since this column is printed months after I write it, you will know), but oil demand should still grow in the longer term. In the short-term, new oil supply additions will get delayed because of the credit crisis. Mega energy projects may get delayed or cancelled, so supply will fall. But a recession will mean that demand for oil uses will decline, too. According to the Financial Times, the floor under the oil price is set by the level at which significant volumes of production become uneconomic, which the 21 December 2008 Financial Times says is around USD 30 to 40. However, if the industry slows down and production costs decline, that level will go even lower.
Modular Syncrude Conversion Drives Oilfield GTL Solution for Associated Gas
Authors: Hopper Chris 
Published: February 2015

Technology Update
The associated gas that accompanies oil to the surface in a producing well can be a great advantage and valuable revenue stream, if your oil field is near a pipeline that feeds into a gas market. However, as oil fields move into deeper and more remote areas, away from population centers and gas infrastructure, the options for handling associated gas have become restricted and the question of what to do with it often difficult. The industry is crying out for a solution.
Historically, where there was no local market or available pipeline, associated gas was flared. However, this is now both environmentally and politically unacceptable, and in many countries banned. The alternative of gas reinjection is expensive and can cause reservoir damage, which adversely affects production and reserves.
Seeking a solution that avoids either of these alternatives, the industry for years has experimented with a variety of technologies.
For example, in areas with large associated gas volumes, the gas can be commingled into gathering systems and supply nearby specially constructed liquefied natural gas (LNG), methanol, or ammonia plants. However, this solution comes with a couple of major requirements.High gas volumes must be com-mitted in advance to justify the substantial plant-building cost.Commonly, supplementary nonassociated gas also must be available to offset supply fluctuations, including the eventual decline of field production. One example of how this supply-balancing requirement can work is the Bonny Island LNG plant in Nigeria, which ran on nonassociated gas until gathering systems were built that allowed associated gas to replace part of the original supply stream.
Without both of these prerequisites, commingling is not an option. With oil fields getting smaller and more remote, there will commonly not be sufficient reserves of associated gas to justify installing gas infrastructure or gas-processing plants. Even in areas such as the North Sea, where extensive gas infrastructure and a ready local market exist, small fields with short lives of 4 years or so cannot justify the expense of installing a gas export pipeline.
Other solutions proposed for dealing with associated gas that cannot be exported by pipeline have involved locating a gas-processing plant adjacent to the oil field and using technologies such as floating LNG, gas-to-liquids (GTL), methanol production, or gas-to-wire electrical power generation. These too tend to require large supplies of gas and considerable investment. For example, a standalone facility capable of consuming 100 to 150 MMscf/D of gas would have a capital expenditure of more than USD 1 billion. In addition, a facility would need a steady nondeclining gas stream, which often can only be achieved by combining associated gas with nonassociated gas from other fields. As such, this has led to these large facilities focusing on stranded gas with reserves of 0.5 Tcf or greater, rather than associated gas.
Industry Braces for an Uncertain Year
Authors: Donnelly John , Parshall Joel 
Published: February 2015

Oil and gas companies are still adjusting to the sharp price volatility, collapse in credit markets, and global economic downturn of the past few months. But many analysts and forecasters believe that the medium- to long-term outlook for the oil industry has not changed, and that the need for more production, more people, and more research and development (R&D) remains.
Given the sharp swings in oil prices the past several months and the unknown depth of the economic recession, the outlook for the oil industry this year is anything but certain. The oil market is still digesting Organization of the Petroleum Exporting Countries’ (OPEC's) 4 million BOPD in production cuts since last September, the organization's steepest cuts in years. Even if OPEC member countries’ compliance with the cuts fall short, a considerable amount of supply will have been taken out of the market. Whether it is enough to make up for the erosion in global demand in the short term is unclear.
The price volatility of the past year has been unprecedented, with oil prices rising to USD 147/bbl before collapsing to under USD 40/bbl. Many OPEC members, including Saudi Arabia, have a target price this year of USD 75/bbl. Standard & Poor's and Moody's, largely watched investment ratings agencies, are currently using WTI price assumptions of USD 55/bbl and USD 50/bbl for this year, respectively.
Oil forecasters, including the International Energy Agency (IEA), the US Department of Energy's Energy Information Administration, and others predict sharp declines in oil demand this year. The consultancy Cambridge Energy Research Associates (CERA) forecasts a 660,000 BOPD decline in demand in 2009, following a 300,000 BOPD drop in 2008, the largest demand fall since the recession of the early 1980s.

The Long-Term View
But in its latest World Energy Outlook, the IEA believes the current economic storm has not changed the market's long-term outlook. It sees world energy use growing more slowly to 2030 than it projected last year, but still expanding by 45% between 2006 and 2030, with an average growth rate of 1.6% per year (Figs. 1 and 2). Fossil fuels will account for 80% of the globe's energy mix in 2030 with oil the dominant fuel. China and India will account for more than half of incremental energy demand to 2030, the IEA predicts, with the Middle East also becoming a key consumption center.
Upstream Global R&D Efforts Continuing, with Caution
Authors: Moon Ted 
Published: February 2015

While 2008 closed with lower demand for oil and gas and a corresponding drop in energy prices from their record highs in the summer, research and development (R&D) efforts across much of the upstream sector continue, although with a sense of cautious optimism. This was one of the findings of a global survey of the state of R&D in the oil field, in which various operators, service providers, and academic institutions were asked to provide insight on the major research projects to which the industry is devoting time, effort, and money.
The survey was sent to upstream professionals around the world, and was aimed at uncovering major research projects, their intended aim, and their stage of development. In addition, professionals were asked if the recent worldwide economic downturn had negatively affected their research efforts or had resulted in cutbacks in R&D spending.
The International Energy Agency still estimates significant growth in energy demand over the next 25 years. Between 2006 and 2030, world primary energy demand is estimated to expand by 45%—an average growth rate of 1.6% per year and one that will be overwhelmingly supplied by oil. To meet this demand, responders have indicated that the industry is developing new technologies along the following major fronts:

Deepwater/Subsea

Baker Hughes.
The oilfield services giant is focused on developing next-generation field development and production technologies for deepwater wells and extreme high-pressure, high-temperature applications. Research in these areas involves ongoing projects that encompass both sustaining engineering and new product development. The company's new Center for Technology Innovation in Houston is the focal point for much of this research, and is capable of testing full-size prototypes of equipment in a test environment with gas pressure up to 40,000 psi and temperatures up to 700°F.

SBM Offshore.
Offshore engineering and installation specialist SBM Offshore Group is developing a steel catenary riser (SCR) connector deployment system for use with deepwater floating production systems. "The aim of this research was to develop a faster, lower-cost SCR lay system using mechanical pipe connectors rather than welded connectors, which are typically used for today's lay vessels," said Jack Pollack, Vice President of Research and Deepwater Development with SBM Offshore. "The mechanical connectors will enable SCRs to be used in deeper water with high-strength pipes and also increases SCR fatigue life, making them applicable to more offshore developments." Research for the SCR deployment system is well under way, and SBM Offshore expects to have a certified SCR connector ready for offshore use in 2009.
Hydraulic Parameters of Underbalanced and Managed-Pressure Drilling
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 114667, "Some - times-Neglected Hydraulic Para meters of Underbalanced and Man aged-Pressure Drilling," by Charles R. Stone, SPE, and Shifeng Tian, SPE, Signa Engineering Corporation, originally prepared for the 2008 SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition, Abu Dhabi, UAE, 28-29 January. The paper has not been peer reviewed.
Successful drilling, especially in very deep wells, may be driven by hydraulic limiting parameters. Two new technologies, underbalanced drilling (UBD) and managed-pressure drilling (MPD) have emerged as solutions to specific hydraulics issues during drilling. A hydraulic parameter can be defined as any factor—mechanical, structural, or fluid—that affects the exertion of hydrostatic head on the open hole. Hydraulic parameters, as a group, must be planned for and managed during all drilling operations to prevent unwanted or unsafe conditions.

Introduction
Hydraulic limits occur in both conventional wells and unconventional wells. The more critical wells experience limits that are unmanageable with conventional techniques; thus the emergence of UBD and MPD. MPD is defined by the International Association of Drilling Contractors as "an adaptive drilling process used to more precisely control the annular pressure profile throughout the wellbore." Simply put, drillers are concerned with the entire pressure profile in the open hole, including the annulus pressure at the casing shoe and the bottomhole pressure (BHP). MPD does not encourage formation influx.
UBD operations involve drilling into any formation where the pressure exerted by the drilling fluid is less than the formation pressure. The technique reduces the hydrostatic pressure of the drilling-fluid column so that the net pressure in the wellbore is less than the formation pressure. Consequently, the formation pressure may cause permeable zones to flow if conditions at the surface allow flow. UBD can facilitate drilling of pressure-depleted formations and lessen formation damage for better productivity. UBD operations include formation influx in the operating plan except in the case of a hole being drilled for rate-of-penetration (ROP) applications in impermeable rock.
In MPD, the driller seeks to stay slightly above or "at-balance" with the downhole pore pressure (PP), or as close to near balance as possible during the entire section of problem hole, during both drilling and connections. Precise control of downhole pressure allows the driller to drill within the window between PP and fracture gradient (FG) without setting casing prematurely.
Deep-Salt-Formation Wells Drilled Successfully With Integrated Techniques
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 115208, "Deep- Salt-Formation Wells Successfully Drilled With Integrated Techniques in Tahe Oilfield," by Zhong Liguo, SPE, Daqing Petroleum Institute; Cong Haiyang, Sinopec; Wang Shiqing, SPE, and Zhao Defu, CNPC; Wang Zhifeng, Sinopec; and Yang Guang, CNPC, originally prepared for the 2008 IADC/ SPE Asia Pacific Drilling Technology Conference and Exhibition, Jakarta, 25-27 August. The paper has not been peer reviewed.
The most challenging drilling problems encountered in the Tahe oil field occur in the deep salt formations. Components of typical salt rocks were analyzed, and salt properties such as plasticity, solubility, stability, and stress sensitivity were measured. As a result of new integrated drilling techniques, deep-salt drilling has been improved substantially.

Introduction
Salt formations are encountered when drilling deeper targets (6000 to 9000 m) in the Tahe oil field in the Talimu basin in China. Challenging drilling problems encountered when drilling these salt formations include wellbore instability, stuck drillpipe, stuck casing, and collapsed casing. The creep deformation of these complex salt formations can cause many complicated downhole conditions such as salt-rock dissolution and wellbore shrinkage.
To improve drilling success through these salt formations, research has been conducted during the past 3 years. The components of typical salt rocks were analyzed, and properties such as plasticity, solubility, and stability were evaluated. Some new techniques were introduced, and integrated techniques were developed.

Salt-Formation Properties
The salt formations are cross bedded and deposited with mud shale more than 5000 m deep. The upper salt formations are thick plaster-stone layers, and lower formations are extrathick salt layers with thin mud interbeds. The total thickness of the salt formations varies from 100 to 300 m. The salt rocks are approximately 80 to 90% sodium chloride (NaCl). The salt formations typically are interlayered with mud formations, with some components inclined to hydrate and expand such as plaster, montmorillonite, and illite, and other salt components tend to dissolve in water.

Creep Deformation.
Salt formations are unstable because of their plasticity, ability to flow, and their solubility compared to stable sandstone formations. For instance, wellbore shrinkage is derived directly from the creep deformation of salt formations. Therefore, it is important to investigate the creep-deformation property of salt formations, which is critical to determine mud density and casing-installation time.
Improved Riser Design for Managed-Pressure Drilling in the Norwegian Sea
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 113672, "Managed-Pressure Drilling Resolves Pressure-Depletion-Related Problems in the Development of the High-Pressure/ High-Temperature Kristin Field," by S.A. Solvang, SPE, StatoilHydro; C. Leuchtenberg, SPE, Consultant; and I.C. Gil, SPE, and H. Pinkstone, SPE, Halliburton, originally prepared for the 2008 SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition, Abu Dhabi, UAE, 28-29 January. The paper has not been peer reviewed.
Depletion of the Kristin high-pressure/high-temperature (HP/HT) field (13,213 psi, 342ºF) is occurring, which challenges the drilling of future increased-recovery wells. The full-length paper describes the need to implement managed-pressure-drilling (MPD) techniques in the Kristin field to overcome the problems related to a narrow drilling window. The Kristin development wells may be the first wells globally to use MPD techniques in a harsh-weather offshore environment on a floating drilling installation.

Introduction
The initial drilling program for Kristin is complete, with 11 wells drilled and completed. Because of the high initial reservoir pressure, the pore pressure declines rapidly with production. Looking ahead at the possible need to drill increased-recovery wells, several challenges to drilling were identified as a result of depletion, particularly with respect to the conventional requirement of keeping the bottomhole pressure (BHP) during drilling above the original pore pressure. MPD allows the safe use of lower mud weights much closer to the conventional drilling-window limits, but to implement such drilling techniques on a floating drilling installation in the harsh-weather environment of the Norwegian Sea, several issues had to be addressed. The equipment used to date for MPD from floaters is not suitable for use on a HP/HT well with Norwegian Sea weather conditions.
Depletion affects both the lower and upper boundary of the drilling-fluid density. This implies that the drilling window changes with depletion. Drilling in a depleted zone is not necessarily a problem; provided that the depleted zone is evenly depleted, that the depletion is known, and that only the depleted zone is open for drilling, the operating window actually may increase with depletion. For the Kristin case, this would imply having the overlying Lange shale behind casing and knowing the pore pressure to be relatively constant in the Garn reservoir. High overbalance in depleted zones also may be a problem with respect to potential differential sticking, formation damage, poor rate of penetration, and drilling-fluid losses.

MPD Implementation
The main technical challenge for enabling MPD on the Kristin project is the closure of the standard marine riser using a rotating control device (RCD), with rig-independent solutions that allow the full retention of the conventional weather operating window, even in the harsh weather conditions seen in the Norwegian Sea.