bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimization Delivers ERD Performance Boost - Sakhalin Island
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 150959, ’Successful Optimization Strategies Combine To Deliver Significant Performance Boost at the Edge of the ERD Envelope-Sakhalin Island, Russia,’ by Richard W. James, SPE, Paul Pastusek, SPE, and Gary R. Kuhn, SPE, ExxonMobil; Anton Andreev, Exxon Neftegas; and Jeffrey R. Bailey, SPE, and Lei Wang, SPE, ExxonMobil, prepared for the 2012 IADC/SPE Drilling Conference and Exhibition, San Diego, California, 6-8 March. The paper has not been peer reviewed.

Many performance-enhancement initiatives were used by the operator of the Sakhalin-I project in drilling and completing the extended-reach-drilling (ERD) program at the Odoptu field, Sakhalin Island, Russia. The initial seven-well ERD program was expanded to nine wells, including the world-record Well OP-11. The operator’s redesign philosophy to remove limiters from the drilling process resulted in significant performance improvements in all areas of drilling and completion operations.

Background

The Odoptu field is one of three fields developed by Exxon Neftegas off the coast of Sakhalin Island, Russia, as part of the Sakhalin-I Project (Fig. 1). The climate is subarctic, with temperatures lower than freezing more than half of the year, and temperatures can drop below −40°C. The field is at the northeastern edge of the Eurasian tectonic plate and is subject to significant earthquake activity, the most recent of which was rated 7.6 on the Richter scale in 1995.   

Drilling began in the Chayvo field in 2003, following mobilization of the Yastreb rig to the Chayvo onshore well-site. After drilling one cuttings-injection well and 20 ERD wells, the Yastreb rig was upgraded and moved to the  Odoptu North wellsite in late 2008. Drilling commenced from the Chayvo offshore well-site with the installation of the Orlan platform in 2005, where an additional cuttings-injection well and 19 ERD wells were drilled.

During the move from Chayvo to Odoptu, significant upgrades were made to the rig on the basis of lessons learned at Chayvo and to accommodate the higher torque anticipated at Odoptu. The new topdrive could deliver 91,000 lbf-ft of torque at 130 rev/min. A larger mast was required to accommodate the new top-drive, and an additional generator was installed. The drillstring was upgraded to provide significantly higher torque capacity. In addition, the handling capacity of the cuttings-injection unit was increased.

Drilling began at Odoptu in April 2009 (with the cuttings-injection well) and ended in February 2011 (with completion of Well OP-2). Although seven ERD wells were planned at Odoptu initially, the program was expanded to nine wells as a result of drilling successes and favorable production performance. The wells included Well OP-11 with 12 345-m measured depth (MD) and 11 479-m horizontal reach. The Yastreb rig has drilled more than 300 000 m of hole. Following the Odoptu program, the Yastreb rig was moved back to the Chayvo onshore well-site to drill additional ERD wells.
Floating 2-MW Turbine Prototype Tests Feasibility of Harnessing Offshore Wind
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 23492, ’Implementation of a 2-MW Floating Wind Turbine Prototype Offshore Portugal,’ by Christian A. Cermelli, Marine Innovation & Technology, and Dominique G. Roddier and Alla Weinstein, Principle Power, prepared for the 2012 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed.

A 2-MW floating offshore wind system prototype was implemented off the coast of Portugal. The project was designed to prove the technical and economic feasibility

of floating offshore wind turbines in southern Europe. It is based on the WindFloat concept, a three-column semisubmersible-platform design with water-entrapment plates. Such technology enables deployment of multimegawatt wind-turbine generators at great distances from shore, in any water depth. Synergies with offshore oil and gas platforms have been exploited; however, deployment in an area with no previous offshore oil and gas activities led to unique challenges.

Project Design Bases

The project design bases were driven by the following principle: The floating wind turbine should be large enough to provide meaningful testing of fabrication, installation, and operation capabilities. Some of the main project design bases were

A location in 49-m-deep water, 6 km offshore Aguçadoura, a small town located north of Porto on the west coast of Portugal

A wind-turbine size from 2 to 2.3 MW

A connection to the country’s main power grid

Although no specific targets were set for local content, the drive to maximize work performed locally was also seen as a critical success factor for the project.

Previous testing conducted during earlier feasibility studies was performed at a 1/67 scale in a model-testing facility. Intermediate-scale testing (between in-door controlled-environment testing in a wave tank and full-scale prototype) was not seen as a necessary step.

Commercial development of floating wind farms will likely be based on the largest available wind turbines. Currently, 3- to 6-MW machines are available for the offshore market; however, because of budgetary limitations and limited experience with wind turbines of such size, the more common and lower-capacity 2- to 2.3-MW turbines were considered optimal for this project.

A testing site 6 km off the west coast of Portugal was selected because of the presence of a subsea electrical cable with sufficient capacity to transport power from the WindFloat prototype to shore.

The target design life for the plat-form is 5 years, but planned operation should not exceed 2 years.
Smart' Buoy Could Turn Waves into Platform and Subsea Power
Authors: Watson Paul
Published: February 2015

Technology Update

The use of moored, oceangoing “smart” buoys that can harvest energy from waves could be an efficient and economic means of supplying electric power for various offshore oil and gas operations, including well trees, monitoring systems, and autonomous underwater vehicles (AUVs). Potentially, such technology could reduce, or in some cases eliminate, the use of diesel-powered generators on offshore facilities.

The PowerBuoy (Fig. 1), developed by Ocean Power Technologies (OPT), is new to the oil industry but has been used for a number of years in the defense and utility sectors. The autonomous buoy system consists of a surface float, a spar containing a power takeoff (PTO), a battery system, and a heave plate that constrains the spar’s motions. The system is capable of delivering energy from a few kilowatts to several hundred kilowatts, with future evolution planned to deliver even more power.

The process begins with the rising and falling of waves, and the resultant mechanical stroking is converted by a specially designed PTO to drive an electric generator. This power is transmitted to external equipment by means of an underwater power cable or directly to payloads integrated into the structure itself. Continuous power is then available with the option of larger, timed power bursts.

Advanced internal control systems continuously monitor the various subsystems and the surrounding environment and optimize performance of those systems with data transmitted to shore in real time, providing health and status updates on itself and its attached payloads. With this information, the operator gains a high level of control. Depending on the model of the buoy, the system is designed to need no maintenance for up to 3 years, providing potential savings in operating and life cycle expenses compared with existing power generation alternatives.

Advanced control algorithms have been developed that actively assess oncoming waves to tune the internal PTO dynamically to ensure that it extracts maximum power. In the event of especially large oncoming waves, the buoy will automatically protect itself by locking the float and PTO subsystems and continuing to supply electric power to its payloads by means of the embedded energy storage system (i.e., batteries). The power management system of the buoy manages the state of charge of the battery to ensure efficient overall system operation and to preserve battery life.
Carbon Dioxide May Offer An Unconventional EOR Option
Authors: Rassenfoss Stephen
Published: February 2015

As the daily oil output of the Bakken and Eagle Ford formations rose toward 1 million B/D, researchers were seeking a way to push the ultimate recoveries in these formations, where producing 6% of the oil in the ground is now considered good.

One line of attack on the problem is using carbon dioxide (CO2) to get more oil from tight formations where rapid production declines are the norm.

In laboratories at the Energy and Environmental Research Center (EERC) at the University of North Dakota and at Texas A&M University, experiments have shown that carbon dioxide circulated around a small sample of source rock can remove a significant amount of oil. Now, the scientists are trying to understand how it works and if those lab results can be applied in the real world.

“It is incredible what CO2 can do,” said John Harju, associate director for research at the EERC, while describing the center’s research program at the annual CO2 Flooding Conference in Midland, Texas.

“The really big prize is (overcoming) the innately low recovery rate in these shale plays,” said David Schechter, an associate professor of petroleum engineering at Texas A&M University who is turning his expertise in conventional enhanced oil recovery to unconventional reservoirs.

While laboratory results normally show much higher recovery than field results, even a 1% improvement of recoveries in the Bakken formation could yield more than 1 billion bbl of oil, according to an EERC paper.

Previous SPE papers, based on reservoir simulation work at Montana Tech of the University of Montana and the Colorado School of Mines, concluded that significant increases in ultimate oil recovery might be possible using CO2 injections.

One of the biggest backers of the work in North Dakota has been Harold Hamm, the chief executive officer at Continental Resources, which pioneered unconventional liquids development and is the biggest acreage holder in the Bakken, Harju said.

On the basis of early tests using CO2 and similar positive results from using chemical surfactants, Texas A&M is working to recruit support from oil companies for a joint industry project called the Enhanced Oil Recovery in Unconventional Reservoirs Joint Industry Project.

Both the EERC and Texas A&M have tested samples ranging in size from Chiclets—square bits of reservoir rock about the size of the popular chewing gum—to small core samples about the size of a disposable lighter. The tests produced significant amounts of oil from samples exposed to CO2 flowing through a test chamber simulating reservoir conditions.
Pioneering Subsea Gas Compression Offshore Norway
Authors: Jacobs Trent
Published: February 2015

The world’s first full-scale subsea gas compression system is in the final stages of construction and is on schedule to be installed in the åsgard gas field offshore Norway by year’s end. Norway’s state-owned oil and gas company, Statoil, says that the project is the largest and most complex subsea development ever undertaken in both size and scope and represents a leap forward for an industry that has sought to produce hydrocarbons ever farther from shore for more than a century. With the ability to process and compress gas far beneath the harsh surface conditions of the Norwegian Sea, Statoil envisions a future where surface installations are not required to develop subsea fields. The concept is referred to as the subsea factory, and the company aims to install one capable of producing both oil and gas by 2020. If successful, the åsgard subsea gas compression project will become the latest milestone in proving that the company’s ambitious objective is possible.

Statoil selected Aker Solutions to design and build the system after determining that a subsea compressor station was economically favorable and had a greater technological potential compared with constructing a semisubmersible platform. By installing a compressor train on the seafloor, “you are closer to the reservoir, which means you can do more with less,” said Svenn Ivar Fure, Aker Solution’s senior vice president of strategy and business development. “You don’t have to take the gas up to a platform and then pump it down again. That provides a lot of advantages,” he said.

Fure also noted that, besides requiring less energy to achieve the same end, a subsea system requires far fewer personnel to maintain and oversee its operation. While subsea facilities do require constant monitoring, it can be done remotely and with far fewer people than necessary for a conventional platform. This provides the operator with considerable saving in regard to salaries, logistical services, helicopter transportation, catering services, and power generation. And, because no personnel work directly on the system day in and day out, the risk for injury and loss of human life is greatly reduced. Additionally, Statoil and Aker Solutions claim subsea compressors involve a simpler build and installation process compared with that of a semisubmersible platform.
ECD-Management Strategy Solves Lost Circulation Issues
Authors: Wilson Adam
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 166134, ’Case Study - ECD-Management Strategy Solves Lost-Circulation Issues in Complex Salt Diapirs/Paleocene Reservoir,’ by David Murray, Shell; Mark W. Sanders, SPE, and Kirsty Houston, SPE, M-I Swaco; and Hamish Hogg and Graeme Wylie, Shell, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed.

Drilling horizontal infill wells in the Pierce field in the UK central North Sea is challenging because of a narrow drilling window caused by depletion in a highly fractured reservoir. Wellbore strengthening was attempted in the reservoir section of Pierce B5 although, when a pre-existing fracture further weakened by depletion was encountered, losses occurred. A detailed analysis of the losses event on Pierce B5 provided an improved understanding of the loss mechanism, resulting in a revised equivalent-circulating-density (ECD) -management strategy.

Introduction

The Pierce field (Fig. 1) in the UK central North Sea is a brownfield development with 17 existing wells drilled around two complex salt diapirs. Oil production was depletion-driven for the first 7 years until pressure support was provided by three water injectors drilled around the southern salt diapir. Pierce B5 was drilled in the proximity of the southern diapir, and losses encountered in the reservoir section were severe enough that no further drilling progress could be made. Preexisting fractures further weakened by depletion were thought to be the cause of the losses. Unfortunately, from a well-planning perspective, these fractures cannot be predicted or avoided when drilling horizontal wells.

During a three-well infill campaign (Wells B5, A11, and C1), considerable losses on the first well led the operator to re-evaluate how future wells would be drilled. The outcome of this was the development of a low-ECD-drilling- fluid system, a revised ECD-management procedure, and a much-improved loss-treatment strategy. This combined strategy was applied in the field and resulted in the successful drilling of the subsequent wells.

Loss Event on Pierce B5

Because of the close proximity in the reservoir of the Pierce B5 well to a preexisting production well (Pierce B2), it was determined that the localized depletion seen at this location because of the drawdown effects of B2 would be on the order of 2,300 psi, which would result in a reduction in formation integrity. However, there was concern that the effects of depletion could be higher than that; 3,200 psi through open fractures was modeled as the worst case. Therefore, because of the potential for dynamic losses when encountering zones that have seen the lowest field depletion and to mitigate the risk of open fractures, the recommendation was made to use a fluid design incorporating wellbore-strengthening materials (WSMs).
Offshore Dry-Docking of FPSOs
Authors: Denney Dennis
Published: February 2015

This article, written by Dennis Denney, contains highlights of paper OTC 24330, ’Offshore Dry-Docking of FPSOs: A Response to Industry Needs,’ by T. Terpstra and E.A. Hellinga, Dockwise, prepared for the 2013 Offshore Technology Conference Brasil, Rio de Janeiro, 29-31 October. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission.

The large number of floating production, storage, and offloading units (FPSOs) commissioned more than a decade ago now require offshore-asset-integrity management and maintenance. The FPSOs were originally designed for continuous service for periods up to 25 years. However, although designed to strict criteria, structural and hull-maintenance shortcomings have become apparent, prompting remedial actions or extensive offshore-maintenance campaigns. An offshore-dry- docking concept was developed to lift an FPSO out of the water without disconnecting it from its mooring system and leaving the flowlines connected. The stable working platform allows work access to the FPSO hull, appendages, and mooring system.

Introduction

The proposed offshore dry-docking concept lifts the FPSO out of the water by submerging the floating dry-dock vessel and moving it underneath the FPSO offshore without disconnecting the FPSO from its mooring system or flowlines, as shown in Fig. 1. The bowless concept of the dry-dock vessel with a high load-carrying capacity enables dry transportation of more-traditional semisubmersibles and other floating production units and FPSOs. The proposed offshore dry dock investigated the use of dry-transportation technology for offshore dry-docking of complete floating production units.

Technical Specifications

The largest heavy-transport vessel currently operating is designed to dry-transport offshore production facilities including ultraheavy semisubmersibles and FPSOs. In the past, an offshore unit would need to be wet towed from the fabricator to its production location. Scaling up the existing heavy-transport vessels was not sufficient because of the length of FPSOs, which can exceed 300 m. A bowless design is capable of transporting and offshore dry-docking FPSOs longer than 300 m, with the strength of the FPSO being the limiting factor. The design is shown in Fig. 2. With its bowless design, the total length of the Dockwise Vanguard (275 m) can be used. Its cruising speed of 12 knots is at least twice the speed of a wet tow. Floating cargoes with a maximum draft of 16 m can be loaded (not considering cribbing or grillage). The dry-dock vessel’s bowless design and the movable casings allow use of the vessel’s entire deck to transport units. Also, there are no vessel restrictions for overhang forward and aft. The bowless design is created by placing the crew’s accommodation on the extreme starboard side of the vessel together with the lifeboats.
Nanotechnology Applications for Challenges in Egypt
Authors: Denney Dennis
Published: February 2015

This article, written by Dennis Denney, contains highlights of paper SPE 164716, ’Applications of Nanotechnology in the Oil and Gas Industry: Latest Trends Worldwide and Future Challenges in Egypt,’ by Abdelrahman Ibrahim El-Diasty, SPE, and Adel M. Salem Ragab, American University in Cairo and Suez University, prepared for the 2013 North Africa Technical Conference & Exhibition, Cairo, 15-17 April. The paper has not been peer reviewed.

Precise manipulation and control of matter at dimensions of 1–100 nm have transformed many industries including the oil and gas industry. Nanosensors enhance the resolution of subsurface imaging, leading to advanced field-characterization techniques. Nanotechnology could greatly enhance oil recovery by use of molecular modification and by manipulating interfacial characteristics. Egypt’s oil consumption has grown by more than 30% in the past 10 years. Hydrocarbon reserves in Egypt have increased 5%/year over the past 7 years, while the average recovery factor remains at 35%. Nanotechnology is key to solving this production/ consumption imbalance.

Introduction

Nanotechnology is the use of very small pieces of material, with dimensions between approximately 1 and 100 nm, by themselves or by manipulation to create new larger-scale materials with unique phenomena enabling novel applications. A nanometer is one-billionth of a meter— a distance equal to two to twenty atoms laid down next to each other (depending on the type of atom).

Nanotechnology refers to manipulating the structure of matter on a length scale of nanometers, interpreted at different times as meaning anything from 0.1 nm (controlling the arrangement of individual atoms) to 100 nm or more. Fig. 1 compares the scale of various items referenced to a nanometer.

Engineered Nanomaterials

Nanoparticles are the simplest form of structures with sizes in the nanometer range. In principle, any collection of atoms bonded together with a structural radius <100 nm can be considered a nanoparticle. The tiny nature of nanoparticles yields useful characteristics, such as increased surface area to which other materials can bond in ways that make stronger or lighter materials. At the nanoscale, size is a factor regarding how molecules react to and bond with each other.

Suspensions of nanoparticles are possible because the interaction of the particle surface with the solvent is strong enough to overcome differences in density, which usually would result in a material either sinking or floating in a liquid-forming nanofluid. Nanofluids for oil and gas applications are defined as any fluid used in the exploration and exploitation of oil and gas that contains at least one additive with a particle size in the range of 1–100 nm. A few oilfield uses are described in the following. See the complete paper for additional uses and details.
New Choke-Valve Design Improves Separator Efficiency
Authors: Betting Marco , Epsom Hugh
Published: February 2015

Technology Update

The efficiency of the gas/liquid separation process can have a significant impact on the economics of planned and potential oil and gas developments, as well as on the profitability of existing production operations.

A new type of choke valve that improves the efficiency of downstream gas/liquid separators by enhancing the coalescence of dispersed liquids in a fluid stream has been developed recently by Twister. The initial field test of the technology, known as the SWIRL valve, was performed at a JT-LTS production unit operated by NAM in the Netherlands.

The test demonstrated that the replacement of a conventional JT valve with the coalescing choke valve resulted in a significant improvement in the dewpointing performance of the gas-processing facility. This retrofit also allowed the maximum plant operating flow rate to be increased from 650 000 to 735 000 m3/d, while still meeting export gas specifications. It was additionally found that by using the coalescing valve, the temperature in the cold separator (SMSM type) could be increased by 4–5°C while still meeting specification, allowing a reduction of approximately 3 bars in the plant feed pressure. Furthermore, it was demonstrated during the field test that the glycol losses normally experienced were significantly reduced.   

This article presents the initial field-test results and an overview of the subsequent development and deployment of the coalescing-valve technology.

Technology Description

Pressure throttling in a conventional choke valve is achieved by dissipation of the kinetic energy present in the gas flow through randomly distributed eddies. The new coalescing valve, which was developed with the aid of proprietary computational fluid-dynamics models, uses the excess free pressure in a fluid stream to establish a coherent vortex motion. The total pressure inside the vortex core is gradually reduced along the axis of the flow path. By reducing the total pressure in a vortex flow, the flow shear rates are lower, compared with conventional chokes, thereby avoiding excessive breakup of liquid drops. However, and more importantly, these micron-size droplets are concentrated around the perimeter of the flow path, thus enhancing the coalescence to larger, more easily separable droplets.
Techbits: Education Best Practices Discussed in Kazakhstan
Authors: JPT staff _
Published: February 2015

Techbits

The SPE Talent Council and the Kazakh National Technical University (KazNTU)—named after prominent Kazakh scientist and academician K.I. Satpayev—sponsored the “Best Practices in Petroleum Engineering Education” workshop in November 2009 in Almaty, Kazakhstan. Adilov Zheksenbeck Makeyevich, rector of KazNTU, was instrumental in bringing this workshop to Almaty, which assembled representatives of academia and industry in discussions related to the quality and quantity of engineering graduates.

The evening before the workshop commenced, a dedication ceremony was held for the SPE/KazNTU Student Chapter Resource Room. Representatives from the SPE Talent Council, industry, university faculty, and students attended the dedication, which highlighted the computer work stations and numerous technical books for use by the student chapter members and contributed by Chevron, Schlumberger, Kappa, and SPE.

Critical Education Objectives Cochairs Mike Sullivan, Tengizchevroil, and Talgat Ablaevitsh, director of the Department of Science at KazNTU, welcomed guests and KazNTU faculty to the workshop, and expressed appreciation to the SPE Talent Council for its support.

Gulnara Sarsenbayeva, director of the Center for International Accreditation at KazNTU, discussed the necessary steps to make KazNTU an internationally recognized university. She stressed that links to the old Soviet educational style must be cut, replaced by new methodologies that are more aligned with a robust international system. Sarsenbayeva discussed the need for stronger links between industry and academia that foster a new sense of cooperation, and advocated that surveys be conducted to assist in the modification and modernization of the university’s curriculum to ensure that it is aligned with market demands.

Ali Ghalambor, professor at the University of Louisiana Lafayette, presented issues regarding accreditation by ABET, a US-based federation of 30 professional and technical societies representing the fields of applied science, computing, engineering, and technology. ABET’s accreditation goals are quality assurance, standardization of evaluation criteria, and uniform criteria benefits to employers and employees (graduates). ABET accreditation places an emphasis on learning rather than teaching, and involves human values that include inquiry-based learning, preparation for lifelong learning, and integrative, systems-based thinking. Basic ABET success criteria to consider include evaluation of student performance, the educational program’s objectives and outcomes, and the quality of the faculty and facilities.
Fluid Selection for Energized Hydraulic Fractures
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 124361, ’Fluid Selection for Energized Hydraulic Fractures,’ by Kyle E. Friehauf and Mukul M. Sharma, SPE, University of Texas at Austin, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 4-7 October.

Traditional hydraulic-fracture simulators do not take into account the compositional, thermal, and phase-behavior effects that are crucial to the success of energized fractures. Traditional water-based fracturing fluids are not ideally suited for use in tight, depleted, or water-sensitive formations. Gas-energized fracturing fluid addresses the water-trapping problem by creating a high gas saturation in the invaded zone, thereby facilitating gas flowback. A fully compositional fracture simulator was used to evaluate different designs for energized fractures. It showed that energized fluids should be applied to rocks when the drawdown pressure is insufficient to remove the liquid. Use of a compositional fracture simulator allows systematic design of energized-fracture treatments. 

Introduction

A hydraulic-fracturing process becomes energized with the addition of a compressible, sometimes soluble, gas component into the treatment fluid. Energizing the fluid creates a high gas saturation in the invaded zone, thereby facilitating gas flowback. It is estimated that one-third of the fractures pumped in the US are energized by a gaseous phase. Energized-fluid fracturing is common in reservoirs that are water sensitive or that have a low pore pressure or low permeability.

In conducting this study, the hydraulic-fracturing model used compositional and energy balances and coupled them with phase behavior, making this model applicable to energized fluids. The productivity-index (PI) -ratio values were calculated with a PI model that takes into account varying fracture conductivity and the damage around the fracture face caused by fluid invasion.

Multiphase-Fracturing-Fluid Properties

As with all fluids, the properties of an energized fracturing fluid depend on fluid composition and the range of conditions under which the fluid is applied. Commonly, CO2 or N2 are added to a traditional water-based fluid to energize the fluid. This paper focused on these fluid systems because they are used most often and because their rheology has been studied to a great extent, but methanol is another possible component. This paper discusses commonly used fluid systems containing the following component mixtures: CO2/H2O, N2/H2O, and CO2/methanol/H2O.
Advanced Production Logging of Horizontal Wells in North Oman
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 13309, ’Advanced Production Logging Review of a Number of Horizontal Wells in the North of Oman,’ by T.K. Chang, SPE, Schlumberger, and L. Mieles and P.J. Tarabbia, SPE, Petroleum Development Oman, originally prepared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December.

The full-length paper reviews the advanced-production-logging jobs performed during 2006–07 in several fields in north Oman. The paper includes the following:

Prejob planning, recommended logging procedures, operational planning and considerations for different types of wells, and well-completion strategy

Factors influencing horizontal production-logging jobs

Evaluation, log quality control, and interpretation of results

Success-rate optimization through candidate selection and best practices  

Introduction

Petroleum Development Oman began drilling horizontal wells in the north of Oman in the 1980s. Since then, most development projects have used a high proportion of horizontal and multilateral wells to access reserves. Historically, downhole inflow patterns encountered in these horizontal wells have been challenging to measure and interpret. Recently, a viable production-logging tool (PLT) was identified to increase understanding of real-time three-phase flow to assist in production optimization and proper well and reservoir management. The full-length paper reviews and analyzes a number of logging jobs conducted in the fields of north Oman.

With any well-related operation, it is important to discuss the success rate of obtaining data. Fig. 1 shows the success rate of the PLT in the producing oil fields of north Oman. Successful jobs are indicated by green and unsuccessful jobs by red. “Technical success” (amber) is on the basis of whether the logging objectives set before the job were met. In some cases, well-workover entries were performed on the basis of the findings from the PLT job, and some production gains have been recorded.

The high success rate (13 successful logging jobs out of 18) was partially a result of proper candidate selection, but mostly a result of proper planning. Of the five unsuccessful jobs, two were a result of tool failures and three were either failure to log the entire interval of interest or inability to log because of operational constraints, giving poor-quality data.
Technology Focus: Heavy Oil (March 2010)
Authors: Matthews Cam
Published: February 2015

Technology Focus

What does the term “heavy oil” mean to you, the broad JPT readership? There are of course the various formal definitions that are tied mainly to API-gravity values (i.e., commonly 22°API), while others reflect both oil density and viscosity (preferentially referring to in-situ conditions). In general, however, recent literature suggests that heavy oil means quite different things to different people throughout this industry because it is used to cover a wide spectrum of reservoir conditions and field developments.

Only a decade or so ago, papers written about heavy oil typically referred to developments in Canada, China, USA (California), or Venezuela. Now, however, papers describing heavy-oil projects cover a much broader range, both geographically and in terms of the reservoir conditions involved, with a key distinction between onshore and offshore developments. Now, various types of onshore heavy-oil developments are under way in many countries and regions including the Middle East (Kuwait, Oman, and Saudi Arabia), Russia, Africa (Chad, Nigeria, Tunisia, and Libya), USA (Alaska), India, and Europe. Over the past few years, interest has grown rapidly in developing heavy-oil deposits off-shore Brazil, Mexico, Africa, China, Italy, Trinidad, Cuba, and elsewhere. These offshore fields include both carbonate and sandstone reservoirs with in-situ oil viscosities typically less than 400 cp. While such viscosity values are quite low relative to traditional onshore heavy-oil developments, they certainly can present significant technical challenges in an offshore environment.

The diversity among these recent heavy-oil developments is significant in terms of the recovery strategies being pursued and the technical challenges that must be overcome. These challenges include choice of recovery method, reservoir characterization and performance, complex-well-design and well-integrity considerations, production and artificial-lift difficulties, as well as fluid-processing difficulties.

The papers included in this feature were selected to showcase the wide range of heavy-oil developments under way throughout the world and the novel strategies and technology pursuits that go along with them.

Heavy Oil additional reading available at OnePetro: www.onepetro.org

PETSOC 2009-067 • “Evaluation of Recovery Technologies for the Grosmont Carbonate Reservoirs” by Q. Jiang, SPE, Osum Oil Sands Corporation, et al.

SPE 113625 • “The Zatchi B Heavy-Oil-Reservoir Development: The Unique Challenges of the TAML6 Multilateral Well ZAM-408ML” by L. Tealdi, SPE, Eni Congo, et al.

SPE 115240 • “Key Technologies of Polymer Flooding in Offshore Oil Field of Bohai Bay” by W. Zhou, China National Offshore Oil Corporation, et al.

SPE 121381 • “When Water Means Oil: Block 16 Case History” by C. Correa Feria, Repsol, et al.
En Route: Innovation and Creativity Needed
Authors: Labastie Alain
Published: February 2015

President's column

Hydrocarbon resources are huge and may be sufficient to satisfy demand for another 100 years or more. But these abundant resources are mostly unconventional hydrocarbons, which are challenging to produce. We will have to deal with shale gas, coal seam gas, bitumens and extra-heavy oil, very tight reservoirs, extreme environments (like ultradeepwater and arctic environment), and oil shales. Also challenging is the oil to be produced by increasing substantially the recovery factor of our existing fields. Putting these hydrocarbons into production will require technology and innovation, capital, and staff well skilled and sufficient in number.

 Innovation will be one of the keys for unlocking future production—new problems will need new solutions. Our innovation will be dependent on how rapidly we develop technology and our creativity in applying that technology. We’ll need new technology in all domains of our activity, including exploration (more subtle traps), appreciation (more complex reservoirs), drilling (cheaper, deeper…), and development and production (new problems due to the nature of the reservoir and the environment). Our creativity will be required to find really new solutions, through step-changes in applications as well as significant new uses of technology.

Certain conditions are needed for creativity to develop well.

Company culture should not be too risk averse (without compromise on safety, obviously!). I believe that in the last 20 years or so, our industry has in general been less innovative and has taken fewer risks than in the past, simply because it was not required, as we had a lot of “easy” production on the radar screen. But we are entering a new era of challenges, and we can already see a change in the attitude of the industry (in the domain of exploration, for example).

Staff should not be overloaded with everyday work, but on the contrary should have some degree of freedom to think forward. This means that a management style that favors creativity is needed. This also means that the historical trend of decreasing the staff count per barrel (or equivalent) produced should be at least stopped.

Staff should be diverse. Diversity in education, cultural background, experience, and gender is also essential to encouraging creativity. I believe that an organization with a staff mostly of male petroleum engineers coming from a small group of universities in the same country would be poorly positioned to address the oncoming challenges.
Swift Acceptance of Innovative Technologies Will Reap Rewards
Authors: Liddle David
Published: February 2015

Guest editorial

It is a hard fact that it is tougher to bring new technology to market in the oil and gas industry than any other, excluding only space exploration. It can take on average up to 16 years from concept to full field deployment, which is almost twice as long as most other sectors. Greater collaboration is a key to breaking down some of the barriers that will help address the many challenges our industry faces.

The common drivers of how to find new resources, maximize recovery of existing reserves, operate fields safely, and ultimately, do it cost effectively will never change, but the mechanisms to propel us forward as an industry will need to. This will require a much bigger investment in research and development to enable ground-breaking technologies.

New technology can make mature fields more cost effective and allow small field developments to become economically viable. The importance of innovation cannot be stressed enough in helping organizations deal more efficiently with a volatile economy. That is why the rate of implementation of proven new technologies needs to be increased.

Full-scale tests must, of course, be completed before a technology can gain market acceptance. Commercializing technology in the oil and gas market place can be costly and time intensive. With many technologies destined for hostile and sometimes remote environments, such as deep waters or high-pressure/high-temperature wells, new developments need to undergo extensive testing and field trials to prove their capability.

Over the past few decades there has been a definite shift in the source of new technology. In the 1980s major oil and gas companies began to decrease their research and development (R&D) spending driven in the main by a decision to “buy versus build.”  As a result, service companies stepped in to partially fill the gap by increasing their R&D spend. Nevertheless, it was only a few years ago that the oil and gas industry was at the top of the league for increased R&D spend, but the recession in the global economy put a dramatic dampener on that position.

The UK Continental Shelf is recognized globally for its excellence in mature province value realization through the accelerated development and use of new technology and innovative practice. There is a strong need to maintain that position through knowledge and skills retention, and stimulation of the innovative community to maintain a creative environment. Also, there exists in the UK an opportunity to transfer some of these skills to other energy industries that should be realized to ensure that the industry capture the ambition of becoming an energy hub now and beyond oil and gas.
BHP Billiton Forges Ahead With Large, Complex Projects
Authors: Donnelly John
Published: February 2015

Company Profile Series

Editor’s note: This is the latest in a series of profiles of leading operators, including key international and national oil companies around the globe.

Although it may be known more for its mining business than its petroleum ventures, BHP Billiton has quietly built an impressive portfolio of large-scale oil and gas upstream projects throughout the world. Its strategy is to continue to undertake massive, complex projects, using a balance sheet that offers a long-term view of its holdings.

BHP Billiton Petroleum—one of the core pieces of the BHP Billiton Corporation based in Australia—has exploration, development, production, and marketing activities in more than a dozen countries around the globe, including a significant deepwater position in the Gulf of Mexico, as well as operations in Australia, the UK, Africa, the Middle East, and Asia. Its worldwide oil exploration organization is located in Houston.

The company’s core upstream oil and gas philosophy is to strive to be diversified globally while focusing on largely proven basins, such as in the US Gulf of Mexico and Australia. The firm also has a range of promising prospects in the South China Sea, Trinidad and Tobago, Algeria, Pakistan, and Malaysia.

BHP Billiton produced 158.6 million BOE in 2010, a 15% increase over 2009 and has posted an 11% compound annual growth rate for output since 2007. Projects in the Gulf of Mexico and Australia contributed largely to the output increase. The firm has had more than 100% reserves replacement the past four years, said J. Michael Yeager, chief executive of BHP Billiton Petroleum. The outlook for production growth this year is flat, however, because of the impact of the drilling moratorium in the Gulf of Mexico brought on by the Macondo disaster.

The petroleum sector’s strategy mirrors that of the larger corporation, with a focus on large projects with a long life span. That makes BHP Billiton different from many of its peers that have smaller assets, said Yeager. In 2010, the company spent more than USD 800 million on exploration and USD 2 billion on development. The spending allowed four major projects to come on stream last year, the latest of which was the Pyrenees oilfield development offshore Western Australia. Pyrenees, the Stybarrow FPSO development in Western Australia, and the Neptune and Shenzi tension leg platforms (TLPs) in the deepwater Gulf of Mexico are examples of the company’s large, technically challenging projects in diverse environments, Yeager said. Over the past four years, the company has tripled its upstream acreage and begun its most aggressive drilling campaign to date.
Technology Focus: Production Operations (March 2011)
Authors: Alhanati Francisco J.S.
Published: February 2015

Technology Focus

While most operators track the amount of water that they produce (a lot), associating a cost figure to it is more difficult. And while there are some obvious cost items, such as drilling and completing disposal wells or chemicals used to enhance oil/water separation, other costs are not that straightforward, such as the share of the artificial-lift and/or corrosion-control costs associated with the water production. A commonly used rule of thumb is USD 0.50/bbl of water; however, this figure can be much higher (e.g., USD 2.00/bbl of water), depending on circumstances. Therefore, when water cuts reach the 90–95% range, operating costs associated with water production can become a significant portion of the total operating costs.

Dealing with this issue adequately is a great challenge. So much so that some believe that accepting to be in charge of a company’s “water-management” strategy is likely a bad career move. Any solutions that involve high capital expenditures, such as a facility expansion, usually are ruled out on the basis of a low rate of return or long-term payout. On the other hand, attempting to use the available water-shutoff technologies often is considered a very risky proposition because results often are uncertain or very short-term; at a minimum, they usually require very good knowledge of the reservoir to be successful. Generally, from an economic standpoint, only options that allow for the upside of more oil production (for instance, by increasing reservoir recovery or debottlenecking an existing facility so that existing wells can produce more) are attractive enough. Nevertheless, as some of the papers featured in this issue (or listed below) illustrate, some people have achieved success. So, there is hope!

Production Operations additional reading available at OnePetro: www.onepetro.org

SPE 131055 “Thief Zones and Effectiveness of Water-Shutoff Treatments Under Variable Levels of Gravity and Reservoir Heterogeneity in Carbonate Reservoirs” by Shawket Ghedan, SPE, Petroleum Institute, et al.

SPE 132253 “Water Management vs. Water Control: Profitability, Not Cost, Driving the Paradigm Change” by E.P. Anthony, SPE, Staatsolie Maatschappij Suriname, et al.

SPE 139336 “An Integrated Methodology for Water Management Under Operational Restrictions” by Eduin O. Munoz Mazo, State University of Campinas, Brazil, et al.

SPE 139308 “Laboratory Development and Successful Field Application of a Conformance Polymer System for Low-, Medium-, and High-Temperature Applications” by J. Vasquez, SPE, Halliburton, et al.