bluuebunny/crossref_metadata_2025 huggingface dataset:
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.
Design of Steel Catenary Risers for Deepwater Offshore Brazil
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 19249, "Influence of Fatigue Issues on the Design of SCRs for Deepwater Offshore Brazil," by A.L.F.L. Torres, M.M. Mourelle, S.F. Senra, E.C. Gonzalez, and J.M.T. da Gama Lima, Petrobras S.A., originally prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed.

Petrobras has been investigating the steel-catenary-riser (SCR) alternative since the beginning of the 1990s. Since then, fatigue verification has been an important issue, demanding good representation of the loading conditions that occur during the lifetime of the riser. The concern with fatigue has motivated Petrobras to research several areas, such as metocean data acquisition, hull design for motion optimization, special touch-down-point (TDP) joints, accurate models for vortex-induced-vibration (VIV) analysis, and the corrosion-fatigue effect.

Introduction

Installation of the P-18 SCR was a pioneer project of a free-hanging SCR connected to a semisubmersible, and it proved the technical feasibility of the concept. Although this riser was installed as a prototype, it is still working in the gas transfer from platform P-18 to platform P-26. It has been monitored since 1999, and the results are being compared with the design data and with simulations performed with in-house computer programs and other commercial packages that include the complete design methodology. Other SCRs were studied, such as the 12-in. oil-export riser for the P-19 semisubmersible in 770 m of water and the 10-in. oil- and gas-export lines for the P-36 semisubmersible at a water depth of 1360 m.

The free-hanging SCR configuration is considered as an available technology for semisubmersible applications, and there is interest in the application of SCRs connected to floating production, storage, and offloading units (FPSOs) because of the trend to use these units for exploration and production in deep water. This has caused a need to study this concept carefully, given the high offsets and heave motions imposed by the vessel at the top of the riser.

Fatigue verification is an important issue that requires accurate evaluation of the loading conditions that occur during the riser lifetime, and it also requires a precise knowledge of construction aspects that could decrease or change riser-materials resistance.

Wave-Induced Fatigue

Over the past few decades, Petrobras has acquired Campos basin wave, current, and wind data, resulting in a metocean database containing more than 7,000 records. Within these data, the occurrence of multimodal/multidirectional sea states was identified. To use this database in riser design, the in-house software tools for structural fatigue analysis were upgraded to consider bimodal/bidirectional sea states.
Management of Offshore-Ice Operations
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 19275, "Ice Management for Ice Offshore Operations," by A.J. Keinonen, AKAC Inc., prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed.

The use of icebreakers in support of offshore-ice operations, and specifically their efficiency in support of vessel-shaped floating platforms in ice, is discussed. New-technology icebreakers equipped with azimuth thrusters achieve high levels of operability with various levels of ice management in a wide range of effective ice thickness.

Introduction

The oil industry has increased its interest in ice-covered waters. Operations, especially in water deeper than 100 m, use various vessels for drilling or production, with icebreakers supporting their station keeping. The use of icebreakers enables stationary operations in ice to continue with increasing degrees of difficulty. The use of vessels in such offshore-ice operations is substantially different from and more demanding than traditional ice-transit operations or port operations in ice-covered ports and terminals.

Offshore-ice projects, which operate in moving pack ice, must ensure that station-keeping operations continue with a high degree of confidence that the station-keeping limits of the floating platform will not be exceeded. Rigorous risk control also is needed to ensure that, if needed, all operations can be stopped and the platform can be removed safely from the location. A high confidence required in the capability to stay on location before such an operation is justifiable. The overall scope of ice management is more accurately "risk management for offshore-ice operations." The following are an integral part of the ice management.Ice and environment intelligenceIce and environment forecastingDefining operability and safe ice operational envelope for the stationary vesselOperational-risk evaluation and assessmentAlerting of operations

Only after the above are completed can the actual physical ice management (i.e., breaking and clearing ice) take place. Safe ice-management logic applies to all floating platforms and to any platforms intended to be removable from their stationary operational locations. This paper focuses on the most demanding version of the ice management, operations of ship-shaped platforms. Vessel-shaped platforms are unique in that they offer a highly favorable ice-interaction condition when ice moves in the direction of the vessel. However, the challenge is that if ice comes from the side, the ice loads are so much higher that the benefit of the low loads in one direction is totally lost and operation might not be feasible.
Lessons Learned From 12 Years of Operations of a Prestressed High-Performance-Concrete Floating Production Unit
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 12546, "Lessons Learned From 12 Years of Operations of a Huge Floating-Production Unit Made of Prestressed High-Performance Concrete," by Bertrand Lanquetin, Heidi Dendani, and Pascal Collet, Total, and Jose Esteve, Bureau Veritas, prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3-5 December. The paper has not been peer reviewed.

Lessons learned from use of a floating-production unit (FPU), made of pre-stressed high-performance concrete, in operation for Total E&P Congo are pre-sented. The unit has been in use for 12 years on the N'Kossa oil field in 170-m water depth. The focus is on structural-modeling techniques, aging processes, and development of an inspection program. The paper is not intended to make a recommendation between steel and concrete, which would entail many other considerations.

Introduction

The FPU NKP is 220 m long, 46 m wide, and 16 m high, with a displacement of 107 000 tonnes. It contains 27 000 m3 of concrete, 2350 tonnes of prestressed steel, and 5000 tonnes of passive steel. During its 12 years of operation, the FPU has undergone one technical stop for process maintenance, as scheduled in the design; otherwise, it has been in uninterrupted service. The unit, shown in Fig. 1, was built in southern France in 1994–95 and installed 1 year later in the N'Kossa oil field in 170-m water depth, 60 km off the Congo coast.

The production facilities and living quarters for 160 people are fitted on the 10 000-m2 deck, which for construction purposes was subdivided into six modules: accommodation and central control, utilities, electric-power generation, gas compression for re-injection, crude oil, and gas. Design production is 16 000 tonne/d of oil and 1300 tonne/d of liquefied petroleum gas. The unit is held in place, 70 m away from the NKF2 platform, with a spread-moored configuration by means of 12 mooring lines.

Asset-Integrity Management

A special method was developed to analyze and monitor the condition of the units. The aim of the floating-units integrity-management process is to ensure management and continuous follow-up of floating units from safety, environmental, operational, maintenance, and quality-management view-points. It includes recommendations on inspection, maintenance, and repairs. This process calls for the following.Structural and anchoring modeling and analysisQualitative [risk-based inspection (RBI)]Yearly reviews of the inspection, repair, and maintenance (IRM) planData management and storage (including reports)Assistance for emergency responseFramework for analysis
Technology Focus: Well Testing (February 2009)
Authors: Stratton Jay
Published: February 2015

Technology Focus

Many of us, at one time or another in our careers, have encountered industry colleagues or team members convinced of the need to gather information, sometimes at any cost. In contrast, just as many struggle with advocating even the most rudimentary data gathering to decision makers within their company. A common problem, particularly in small companies, can be a tendency to make quick decisions without considering possible effects by relying on past experience and judgment to expedite decision making for new problems. Planning can seem bureaucratic and unnecessary, particularly to less-experienced or nontechnical professionals. However, when objectives are not established and deliverables are not determined before making the final decision, the result can be a large invoice and information or service that is essentially useless.

Modern software, sometimes with less effort than my children put into mastering the latest "Xbox 360" release, will transform any kind of input data into an impressive array of results that can provide compelling justification for a completely wrong conclusion. I am picturing trainloads of investors passing through early oil fields where a strong pump and full tank battery could provide an impressive "gusher" timed by the promoter for just the right moment! And even a cursory look at input and assumptions going into some of our modern analysis can keep us from drawing wrong conclusions. Along with colorful or animated results, the most useful and relevant analysis in our industry will always invest the necessary time to confirm quality of the input data and verify the purpose or application of the results.

The papers highlighted on the following pages provide good examples of how unmet needs can provide insight into better analysis methods. New tools result from the need to acquire important information that would otherwise be uneconomic. Thorough engineers and technicians will be interested in the accuracy of their analysis as it relates to the quality of the input data. Solid analysis over time can uncover further insight into the performance of a hydrocarbon asset. I hope that you will find the selected papers of interest and that they will provide stimulation for new approaches in your well-testing and surveillance activities.

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

SPE 116744 • "Equivalent Skin Factors for Nonuniformly Damaged Horizontal and Multilateral Wells" by Turhan Yildiz, SPE, Colorado School of Mines

SPE 118940 • "Evaluation of Skin Factor From Single-Rate Gas-Well Test" by K. Aminian, West Virginia University, et al.

Additional reading available at OnePetro: www.onepetro.org

OTC 19140 • "Oilwell Transient Testing by Injection of Miscible Liquid" by J.J. Voelker, SPE, Chevron
Techbits (March 2004)
Authors: JPT staff _
Published: February 2015

Techbits - No abstract available.
Unlocking Profitability by Rejuvenating Brownfields
Authors: Corrigan Mark
Published: February 2015

Management - No abstract available.
Spotlight on R&D: Reservoir Description and Dynamics
Authors: Horne Roland , Raghavan Raj
Published: February 2015

Spotlight on R&D series - This is the second of a series of articles on the state of research and development (R&D) in the major upstream technological disciplines. The Spotlight on R&D Series, comprising articles published in JPT during 2004 and 2005, is available as a collection on OnePetro (SPE-101432-JPT).
Overview: Hydraulic Fracturing (March 2004)
Authors: Wildt Pat
Published: February 2015

Overview - No abstract available.
High-Permeability Fracturing: "Carter" Fluid Loss or Not
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 86550, "High-Permeability Fracturing: 'Carter' Fluid Loss or Not," by Michael B. Smith, SPE, NSI Technologies, Michael Bose, SPE, Anadarko Petroleum Co., Henry H. Klein, SPE, HK Technologies, Brent R. Ozenne, SPE, Newfield Exploration Co., and Ron S. Vandersypen, SPE, NSI Technologies, prepared for the 2004 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 18-20 February.
Downhole Oil/Water Separation Systems in High-Volume/ High-Horsepower Application
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 81123, "Downhole Oil/Water Separation Systems in High- Volume/High-Horsepower Application," by Yasser K. Bangash, SPE, Wood Group ESP Inc., and Marcello Reyna, Intevep-PDVSA, prepared for the 2003 SPE Latin American and Caribbean Petroleum Engineering Conference, Portof- Spain, Trinidad, 27-30 April.
Overview: High-Pressure/High-Temperature Challenges (March 2004)
Authors: MacAndrew Robert
Published: February 2015

Overview - No abstract available.
Microstructural Optimization Results in Stress-Resistant HP/HT Cement
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 84562, "Producing Stress-Resistant High- Temperature/High-Pressure Cement Formulations Through Microstructural Optimization," by Dan T. Mueller, SPE, BJ Services Co., prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
Field Application of an HCl/Formic Acid System to Acid Fracture Deep Gas Wells
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 84925, "Field Application of HCl-Formic Acid System to Acid Fracture Deep Gas Wells Completed With Super Cr-13 Tubing in Saudi Arabia," by H.A. Nasr-El-Din, SPE, S.M. Driweesh, SPE, and G.A. Muntasheri, Saudi Aramco, prepared for the 2003 SPE International Improved Oil Recovery Conference, Kuala Lumpur, 20-21 October.
Planning Successful EOR Projects
Authors: Hite J. Roger , Avasthi S.M. , Bondor Paul L.
Published: February 2015

High oil prices and concerns about future oil supply are leading to a renewed interest in enhanced oil recovery (EOR), a group of technologies that can significantly increase recovery from existing oil reservoirs. Most of the experience with EOR is still in the United States, principally with CO2 flooding in the Permian Basin in west Texas and with the several thermal processes in the San Joaquin Valley in California. A listing of these projects is compiled every 2 years. But worldwide applications are growing. Thermal recovery of bitumen in Alberta, Canada, is increasing rapidly, and thermal projects have been successful in Venezuela, Indonesia, and elsewhere. Chemical and polymer floods are being implemented in China.

New applications increasingly will be worldwide. Each one will depend on careful planning to design an EOR project specific to the properties of the oil, the reservoir conditions, and the availability of injectants. In many situations, new EOR technology will be necessary. The processes being applied in the United States were tailored for those conditions and do not necessarily translate to other geologic provinces. This article attempts to distill past experience to define the state of the art in planning EOR projects. It is grounded in more than 30 years of experience by the authors in a wide variety of EOR applications.

The Planning Process

Successful EOR project management depends on good planning. “Prior proper planning prevents poor performance,” they say, and it is especially true when EOR is involved. Planning includes:

- Identifying the appropriate EOR process.

- Characterizing the reservoir.

- Determining the engineering design parameters.

- Conducting pilots or field tests as needed.

- Finishing with a plan to manage the project to meet or exceed expectations.

From the outset, and at every step along the way, we strongly recommend that careful attention be paid both to economic studies and to reservoir simulation as the reservoir characterization and engineering design progresses. In this way, the chances of success are greatly improved. Fig. 1 illustrates the interaction of all three.

Economics is the ultimate project driver. After all, unless the project is comfortably profitable, it should not be pursued in the first place. But reliable economics need good performance predictions. Good simulation models need good data. And what data are needed is determined by which project elements the economics is sensitive to. Each guides and depends on the others.
Practical Diagnostics Using Production Data and Flowing Pressures
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 89939, "Practical Diagnostics Using Production Data and Flowing Pressures," by David Anderson, SPE, and Louis Mattar, SPE, Fekete Assocs. Inc., prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.

Three important advances in production-data analysis are the inclusion of flowing pressures into analysis methods; the use of a “boundary-dominated” equivalent-production-time function to make constant rate and constant pressure equivalent; and the use of pseudo-time, which corrects for gas properties varying with pressure. Their value depends on the quality of real production data and, more importantly, the analyst’s ability to filter out the “junk” and retain the true reservoir signal. Blind application of decline-analysis methods without consideration of data-quality issues can lead to misinterpretation and erroneous results. Several practical diagnostic procedures, some general and others specific, can be applied to production data both on simple production charts and on advanced type curves.

Introduction

Most concepts underlying production-data analysis are based on pressure-transient (drawdown) theory. A model based on diffusive fluid-flow physics is used to describe the reservoir, fluid, and well as a system. Like well-test analysis, production-data-analysis techniques use type curves, which enable quantitative and qualitative evaluation of a system by identifying and matching trends in the data that are similar to the shape of the underlying type-curve model. Superposition in time converts variable inner-boundary conditions into an equivalent constant inner-boundary condition (usually constant production rate). In pressure-transient analysis, this superposition time usually is based on radial flow, while in production-data analysis, it is based on boundary-dominated (depletion) flow (i.e., material-balance time). An issue that is unique to long-term production-data analysis is the handling of fluid properties that vary with pressure. This issue is critical during depletion of a gas reservoir because the strongly varying compressibility is the dominant term in the depletion equation. The correction is a concept called pseudotime.
Acoustic Stimulation to Mitigate Near-Wellbore Damage
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 90356, "Acoustic Stimulation to Mitigate Near-Wellbore Damage," by Fred van der Bas, SPE, Eric de Rouffignac, SPE, and Pedro Zuiderwijk, SPE, Shell Intl. E&P B.V., and Diederik van Batenburg, SPE, Halliburton, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 October.

Near-wellbore formation damage reduces productivity in oil and gas wells. Formation damage can be caused by fluid invasion during the drilling and completion process and by particles in the production stream. The conventional technique to remove this damage is fluid injection to dissolve the damage. A promising new technique to remove the near-wellbore damage is high-frequency acoustic stimulation. A specially designed acoustic tool is deployed on wireline or coiled tubing (CT) to selectively treat damaged reservoir intervals.

Introduction

Near-wellbore formation damage can result from many activities during drilling, completion, and production. One of the most pervasive damage mechanisms is pore plugging by solid particles from drilling mud, drilled solids, or particles from the formation. It is not always possible to prevent formation damage, and well-stimulation techniques have been used to remove or mitigate the effect of formation damage for more than half a century. Although conventional well-stimulation techniques have been used very successfully, they have significant limitations in long horizontal wells and in wells with multiple branches.

Acoustic cleaning is a promising well-stimulation technology that complements existing stimulation technologies and extends the range of options available for cost-effective well stimulation. High-frequency sound waves are used to “shake loose” damaging particles, and their effectiveness can be enhanced substantially by maintaining an underbalanced pressure in the well.

The experiments described in the full-length paper are the first, to the authors’ knowledge, to be conducted with oil and connate water. The ultimate proof of acoustic-stimulation feasibility requires field trials.
Reliability by Design - HP/HT System Development
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 16393, "Reliability by Design - HP/HT System Development," by Dave Harrold, Eric Ringle, Michael Taylor, Scott Timte, and Frank Wabnitz, FMC Energy Systems, originally presented at the 2004 Offshore Technology Conference, Houston, 3-6 May.

The full-length paper details the design and qualification of a subsea completion system for the technically challenging high-pressure/high-temperature (HP/HT) environment. The focus is on the application of reliability engineering from the concept-development and design stages to the equipment-qualification process and how use of a comprehensive reliability-assurance program influenced the decision-making process and resulted in a highly functional and reliable system.

Introduction

Worldwide, the larger reserves of oil and gas that were located in the more accessible and, therefore, economically attractive shallow-water regions are being depleted. This is leaving operators with the choice of either pursuing the remaining, economically marginal, shallow-water finds or moving into deeper water. In the past 2 years, more than 20 new deepwater discoveries have been made in the Gulf of Mexico (GOM) alone.

The economics of deepwater developments depends heavily on equipment performance, mainly maintaining high system availability. For deepwater applications, operators are requiring system-availability numbers greater than 95% just to ensure that the projects remain economically viable. Although achievable, these targets exceed the expected availability for shallow-water applications. To be profitable in deep water, the higher production rates must be not only realized but also maintained throughout the life of the project. Downtime is considered unacceptable, especially problems caused by equipment failure.

Since 1948, the true vertical depth of the deepest well in the GOM has more than doubled to the current record of 29,680 ft. Drilling deeper takes longer and, therefore, costs more. As much as half of the cost of drilling a deeper well can be spent in just the last 10 to 25% of the total well depth, where rock formations are harder and pressures and temperatures are higher. Wells drilled beyond 20,000 ft can be even more problematic because of the high probability of encountering HP/HT conditions. Although a universal definition for HP/HT has not been established, most operators consider any well with a bottomhole temperature greater than 300°F and surface shut-in pressure greater than 10,000 psi as an HP/HT application. While HP/HT conditions are not new for onshore and offshore platform applications, the first true subsea HP/HT completion has yet to be brought online.
Case Study: Statistical Risk to a Drill Center From Shallow-Water Flow
Authors: Cundiff Les W. , Daugherty Bill , Mix Kurt
Published: February 2015

Development projects in a number of deepwater provinces face the risk of shallow-water flow (SWF) from overpressured water-bearing sands. Typically found 1,000 to 3,000 ft below the mudline, these sands are often drilled before riser installation and can flow against a saltwater gradient. In extreme cases, vigorous flow will cause borehole rugosity or cavities from sand mining. After casing installation, poorly isolated SWF sands can flow, causing subsidence and casing buckling in both the afflicted well and its offsets. This article describes the evolution of SWF discovery, analysis, and mitigation on BP’s Atlantis project, located in 6,900 ft of water in southern Green Canyon.

The earliest seismic images of Atlantis had shown a possible SWF sand at 9,200 ft, some 2,300 ft below the mudline, that generally covered the entire prospect. Drilling revealed a pore pressure of 9.2 ppge for this zone, which was successfully cased by the first four wells on the prospect.

The fifth well, GC 743 #4, was spudded in July 2002. Drilling progressed below the 36-in. jet string at 7,100 ft toward the next planned casing point at 10,250 ft. At 8,400 ft, a 100-ft sand was drilled that had not been seen on seismic or in previous wells. The sand flowed against salt water during drilling, and at least some degree of sand mining occurred. After “pumping and dumping” to casing point at 10,250 ft, pad mud was spotted and the drillstring was retrieved to run 20-in. casing. The 20-in. shoe hit a ledge or bridge at the 8,400-ft sand, buckled above the wellhead, and parted. GC 743 #4 was cemented and abandoned after unsuccessful fishing attempts. A replacement well, GC 743 #6, was drilled 195 ft away with an additional string of 26-in. casing set above the newly identified 8,400-ft sand. Surprisingly, the sand was absent in this well, as shown in Fig. 1.

With the data from these two wells, recently acquired high-resolution seismic revealed vague images of a steeply banked sand-filled river channel meandering through DC-1, the primary Atlantis drill center. But seismic resolution was inadequate to map the exact boundaries of the sand. Bathymetry and proximity to the Sigsbee Escarpment prevented relocation of the drill center. With sanction approaching, an additional string of 26-in. casing, top set above the newly problematic 8,400-ft sand, was included for each of the 15 remaining wells.

Atlantis was sanctioned in November 2002 with the casing design shown in Fig. 2. A slimmer version, shown in Fig. 3, was under consideration at the time to reduce high “pump and dump” mud volumes experienced in GC 743 #4. The sanction work scope provided for a continuous batch-setting program for the remaining wells.
Guest Editorial: Oil and Efficient-Market Theory
Authors: Schulz Rodney
Published: February 2015

In 2003, well-known economist Eugene Fama was nominated for the Nobel Prize in economics for work pertaining to his efficient-market hypothesis. Since the 1960s, that hypothesis has been researched, applied, and debated mostly in the context of stock markets. But the theory has measurable applicability to how we go about our daily business in the oil and gas industry.

In short, the efficient-market hypothesis states that a free and open market, such as the New York Stock Exchange, adjusts its prices almost instantaneously to all publicly available information. That suggests that one cannot predictably, consistently outperform market returns through fundamental or technical analysis of publicly available information. But what is considered "publicly available information"? Just about everything that happens outside a boardroom and much of what happens inside a boardroom. The market reacts, quickly and efficiently. It may not always be "right," but it will react and continually readjust almost instantaneously. Another part of the hypothesis states that price movements in the market follow a "random walk" pattern (i.e., price movements are random and the best predictor of tomorrow's price is today's price).

Taking the hypothesis to its next logical step implies that analysts and active stock investors cannot predictably, consistently outperform market returns by selectively placing bets on particular publicly traded investments. Although this flies against the beliefs and marketing strategies of most mutual funds and Wall Street firms, an extensive number of studies over the years indicate that passive, market-driven investments outperform active, arbitrary investments.

Applications to the Oil and Gas Industry

Looking at the oil and gas industry, one immediately finds evidence of market efficiency with oil and gas prices. First, if the market were not efficient, firms that did nothing but trade oil and gas futures would be as ubiquitous as independent producers. Moreover, they would perform as well in down markets as in up markets. This would be an easy business to start, as there are almost no barriers to entry. However, firms that do nothing other than trade oil and gas futures are practically nonexistent. One sees few, if any, traders who do nothing other than trade futures paper or buy crude oil in a Cushing, Oklahoma, tank today and sell it in the same Cushing tank tomorrow, for a profit.

One may argue that the oil market is not efficient because a few large players, such as some of OPEC's largest producers, have the ability to move prices. And that is true, as well as the fact that insiders in those organizations can take advantage of certain information. But this is true in many industries, particularly those dominated by a few large concerns that everyone else follows. However, having dominant industry players does not mean that the market of buyers and sellers does not incorporate all publicly available information almost instantaneously. The world reacts to OPEC's moves as soon as they are discovered.
Management: How Do We Get There From Here? Global Energy Transitions Planning
Authors: Ebenhack Ben W.
Published: February 2015

How shall we craft an energy future less dependent on petroleum? And what role will oil and gas play in that scenario? In spite of an impressive 150-year track record of increasing hydrocarbon production to meet growth in demand, constraints are emerging. There will be a pinch in production rates relative to growing demand, necessitating the development and deployment of alternative energy technologies from more sustainable resources. As of yet there is no consensus on how to transition to alternative fuels despite a great deal of talk about doing so.

Predictions of oil's demise have plagued the petroleum industry since its birth. Repeatedly, doomsayers have suggested that the world had no more than 20 or 30 years of oil left. The repeated failure of these dire predictions have led some to dismiss the finitude of petroleum resources completely—even claim that the world can never run out of oil.

These optimists are as correct in an absolute sense as they are ridiculously wrong in a practical sense. No matter how high the price of petroleum becomes no technology will ever extract every drop from the proven, producing reserves, let alone find every small reservoir that exists. The decline of petroleum is neither total nor sudden. But in a practical sense, a crisis will come when production can no longer keep pace with demand growth. At that time, we will be producing more oil than ever before! Petroleum production will reach a peak and ultimately decline. That peak will occur when surplus production capacity has diminished to zero and demand continues to grow (unless some alternative source succeeds in carving out a major market share very soon).

In his book The Long Emergency, James Howard Kunstler speaks of "delusional thinking" in regard to pinning hopes on emerging alternative energy technologies. But while the issue is muddied by ignorant, alarmist, and simplistic declarations of the end of petroleum, it is just as badly muddied by denial. Julian Simon, in his popular, highly misleading text The Ultimate Resource II, has a chapter titled "When Will We Run Out Of Oil? Never!" It is true that petroleum has been increasing in the marketplace. Demand has been growing steadily for more than 130 years, and thus far, the industry has kept pace. However, it is utter, antiscientific fallacy to draw any conclusions about the physical limits of the petroleum resource from economic data. The decline will come.
Overview: Production Operations (March 2007)
Authors: Poe Bob
Published: February 2015

Welcome to the Production Operations feature once again. Some of the issues that production-operations engineers must address in their daily work include multiphase flow in production systems, well-productivity changes, and production-performance testing and analysis. These issues often are compounded when compositional changes occur in the produced reservoir fluids, as is commonly encountered in the production of gas-condensate reservoirs.

This year's Production Operations feature includes some very interesting research and some practical applications of the measurement and evaluation of well performance in multiphase-flow operations. There is significant need for a better understanding of the complex phenomena associated with multiphase flow in production systems, including the metering of fluid flow, the effects that multiphase flow and reservoir-fluid-compositional changes have on well productivity, and the overall production-system performance under multi-phase-and nonlinear-flow conditions.

With improved multiphase-flow metering and testing, improved wellbore multiphase-flow modeling, and more-realistic well-completion-efficiency evaluation, the production-operations engineer can make better-informed decisions about a well's performance and its potential for improvement. The articles presented in this issue highlight some of the advances being made to improve the measurement and evaluation of the production performance of wells in oil and gas-condensate reservoirs.

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

SPE 103255 "Optimizing the Productivity of Gas-Condensate Wells" by C. Shi, SPE, Stanford U., et al.

SPE 102231 "Modeling Nonisothermal Rapid Multiphase Flow in Wells Under Nonequilibrium Conditions" by G. Michel, U. of Oklahoma, et al.

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