bluuebunny/crossref_metadata_2025 huggingface dataset:
Polymer Injection in a Deep Offshore Field - Angola, Dalia/Camelia Field Case
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 135735, ’First Polymer Injection in a Deep Offshore Field - Angola: Recent Advances on Dalia/ Camelia Field Case,’ by Danielle Morel, SPE, and Michel Vert, Total E&P; Stephane Jouenne, SPE, Total Petrochemicals; and Renaud Gauchet and Yann Bouger, Total E&P Angola, prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. The paper has not been peer reviewed.

Key challenges of the polymer-injection project in the Dalia field, offshore Angola, were to start polymer injection:

Very early in the field development

With much wider well spacing than in other projects

Under high-salinity conditions (>25g/L)

With specific logistics of a remote deep offshore area

Introduction

The Dalia field is 130 km offshore Angola, with an estimated 1 billion bbl of recoverable oil. Water depth varies between 1200 and 1400 m, with reservoirs 800 to 1000 m below the seabed. Very-high-quality 3D-seismic data enabled mapping of the main reservoir structure, including sands and clay areas only 6 to 10 m thick. The channel complexes can be as thick as 100 m but are divided into heterogeneous sections with alternating layers of oil sands and clays. Permeability ranges from a few hundred millidarcies to several darcies, with an average permeability greater than 1 darcy. The reservoir temperature ranges from 45 to 56°C, and reservoir pressure is 215 to 235 bar. The 19 to 38°API oil is slightly undersaturated, with viscosity ranging from 1 to 11 cp at reservoir conditions. Water viscosity is approximately 0.5 cp at reservoir conditions.

The field produces by energy from water injection, using a floating production, storage, and offloading (FPSO) vessel with 31 deviated or horizontal subsea injector wells and four injection flowlines. Generally, a single flowline is used to inject into several reservoirs and several systems. Maximum water injection is 405,000 BWPD. Production is achieved through four production lines and 37 producers. First oil was on 13 December 2006. The 240,000-BOPD plateau rate was reached after a few months and has been maintained since.

Seawater is desulfated to prevent risk of barium sulfate deposit, and has been injected from the start. Produced water will be reinjected after water breakthrough. By June 2010, 25 producer wells were connected and water breakthrough had occurred in several wells, with water cut ranging from a few percent to more than 40%. The current water-injection salinity is approximately 50 g/L.
Downhole Fiber Optics Are Changing the Well's Footprint
Authors: Powers Greg
Published: February 2015

Guest editorial

“Ephemeralization” is the term coined by engineer Buckminster Fuller, the father of the geodesic dome and an early environmental activist, to describe the advancement of technology that achieves “more and more with less and less until eventually you can do everything with nothing.”

This idea of doing more with less is at the heart of advances in downhole fiber-optic technology, and, in relative terms, its application is not far removed from doing nearly everything with almost nothing.

Using light-transmitting optical fibers slightly thicker than a human hair and similar to the technology that brings Internet capacity to your home, we have been measuring wellbore parameters such as temperature, pressure, strain, vibration, and sound (acoustics) for years. In the near future, with the development of new optical or photonic sensing methods for chemical, microdeformation, resistivity, magnetic field, and other monitoring solutions, the industry will be able to integrate, visualize, and analyze numerous operations and activities downhole in real time, thus extending the life of the well and the reservoir.

More Photons, Fewer Electrons

Fuller illustrated his concept of ephemeralization by comparing the tons of copper wire required for a trans-Atlantic communication cable that could be replaced with ounces of the copper wire that it takes for a single communications satellite. With fiber-optic cables, the comparison is equally dramatic in many ways.

Legacy electronic systems require deployment of complex, dedicated downhole instruments with millions of transistor junctions to make discrete wellbore measurements at specific points and times. In marked contrast, fiber-optic technology uses low-cost, low signal loss, high-bandwidth, silica glass transmission lines down-hole in concert with surface optoelectronic instruments to continually acquire real-time, remote, fully distributed measurements over the entire length of the installation, making the solution highly scalable.

Leaving instrumentation on the rig floor, and not within the wellbore, removes risk from the hostile environment and enhances operating parameters. For instance, fiber-optic sensing and monitoring have been used in environments of up to 300°C (572°F) for years with great success. Solutions exist today for much higher temperatures. In contrast, electronic solutions are limited to less than about 200°C (392°F) for permanent deployment.

As the technology evolves, surface instrumentation can be upgraded and connected to the same downhole fiber-optic sensors, instantly providing better data and potentially new sensing applications. For example, instrumentation connected to fiber-optic cables originally deployed on pipelines for telemetry decades ago is now being used to monitor distributed flow, temperature, acoustics, and tubular strain across many kilometers, thus enabling leak detection, flow restriction identification, object tracking, and other capabilities.
Stage Multiplier Technology Provides Ultrahigh Stage Numbers
Authors: JPT staff _
Published: February 2015

Young Technology Showcase

In December 2011, a record-setting 60-stage openhole fracturing system was installed in the Marcellus Shale in western Pennsylvania. One of the key technologies that enabled this application is a new stage multiplier device called the Packers Plus RepeaterPORT sleeve, which allows the same sized ball to be dropped multiple times. Initially, reservoir fracture modeling indicated that a relatively small number of planar fractures would adequately drain unconventional resource plays such as shale and ultratight rock for both oil and gas. However, empirical evidence has shown that this is not the case. No matter which completion technique is used, stage numbers have been increasing and spacing between fractures has been decreasing. In many cases, however, operational efficiencies are nearing an economic limit for conventional cemented liners and plug-and-perforation completions.

Long planar fractures may not be the best approach to effective resource recovery; instead, shorter fractures, smaller fluid volumes, and higher stage numbers have increased productivity and ultimate recovery numbers by as much as 50%. In addition, liquids and condensate numbers (bbl condensate/MMcf/D of gas) increase with openhole completions and ultrahigh stage density.

Technology Description

The stage multiplier technology operates by allowing the ball to pass through the port, putting it through a passive shift that does not open the port but instead moves it to the next operating position. Subsequent balls of the same size will either provide another passive shift or prime the port to be opened with the next ball. In the latter case, the ball will move the port to an active shift position allowing the next ball to shift it to the open position.

This technology creates a number of advantages. First, the ability to run the same size ball multiple times enables an increase in stage numbers—currently up to 60 stages in 5½-in. casing. A second advantage is that the smallest port size can remain relatively large compared with other approaches, reducing accumulated friction from fluid passing through multiple port restrictions. In addition, access with coiled tubing is enhanced for operations such as production logging and well cleanout. Third, operational efficiency is greatly enhanced by allowing uninterrupted stage-to-stage advancement. Furthermore, pumping rates can be reduced, saving on hydraulic horsepower and equipment requirements, because single intervals are being treated per stage rather than three or four perforation clusters. This means that the effective rate will be similar for individual intervals, but the total pump rate at surface can be reduced by approximately one-third, thus saving on surface treating pressure and friction while pumping.
Knowledge Management In the Digital Age
Authors: Hubert Cindy
Published: February 2015

Management

The project challenges of the oil and gas industry are characterized by change and uncertainty. Work operations span the globe and smooth working partnerships cannot be anticipated. However, we can confront that uncertainty by becoming more agile. Greater levels of agility rest upon using the power of knowledge—the cornerstone of successful corporations.

The difference between a powerful knowledge management (KM) program and the also-ran is the ability to identify and enable critical knowledge. The KM system is a tool and not the end product. People still make the system work and are the critical component for input, expert collaboration, and mentoring. In fact, business value is created when critical knowledge gets to the right person at his or her teachable moment and is applied. The crucial knowledge set within your organization is often hidden—sometimes buried—because it resides in people or in many electronic reports or in stacks of lessons learned. The question we need to ponder is this: Can too much knowledge flow?

What Is Knowledge Management?

From a practical perspective, knowledge is information in action. Until people take information and use it, it is not knowledge. In a business context, knowledge is what employees know about their customers, each other, products, processes, mistakes, and successes, whether that knowledge is tacit or explicit.

The American Productivity and Quality Center (APQC) defines KM as a systematic effort to enable information and knowledge to grow, flow, and create value. The discipline is about creating and managing the processes to get the right knowledge to the right people at the right time and help people share and act on information in order to improve organizational performance. Organizations implement a KM program to institutionalize and promote knowledge sharing practices. An enterprise program is usually a centralized, organizationwide effort to standardize and excel in KM.

Strategy in a New Context

The defining book on how to implement an effective KM strategy was written in 1998 when the discipline was less than a decade old (If Only We Knew What We Know by C. O’Dell and C.J. Grayson). Since then, we have seen many momentous changes affecting KM: rising Internet and broadband access, the explosion of mobile devices and smartphones, the continued rise in virtual work and global teams, the international equalization of competitive prowess and knowledge, the decline of readership for the printed word, the rise of digital readership, and so on. It would be hard to overstate how profoundly these developments have both challenged and enhanced the promise and practice of KM. The core objectives have not changed, but how we accomplish them has.
Technology Focus: Coiled Tubing Applications (June 2012)
Authors: Misselbrook John
Published: February 2015

Technology Focus

The coiled-tubing (CT) industry has experience unparalleled growth in the past year, driven directly by the massive expansion in multistage-fracturing operations in North America. Various sources estimate that the US consumed 50% of the world’s CT in the past 12 months, helping to contribute to a massive 80% growth in product coming off the CT production lines.

The growth in the United States was fueled primarily by three applications: milling out composite plugs, milling out fracture-sleeve ball seats, and toe shoots (the name given to the first perforating operation before plug-and-perforate operations). Because toe shoots take place without any pressure on the well, the amount of CT life consumed by fatigue during the operation is small. Plug or seat milling, on the other hand, takes place after fracturing operations are complete and with the wellbore fully pressure charged by the formation; therefore, the CT life consumed by fatigue is high. Superimposed over the wellbore pressures are the pressures arising from circulating fluids through the CT and the milling assemblies. In some of the higher-pressure shale plays, CT strings last only for a few jobs.

Accordingly, any technology that reduces the superimposed pressure could lead to longer CT life and potentially to lower completion costs. Two of the papers selected for this month’s issue involve new technologies that might be helpful to operators in this respect.

However, of possible greater concern to CT companies in North America is the fact that CT use is now clearly dominated by well-completion operations, or, to put it another way, by rig count. Until recently, the CT intervention business was primarily remedial in nature and, thus, was partially cushioned from the extreme cycles experienced by drillers. However, in North America, a change has already arrived and, with gas prices at historic lows, CT service companies, CT pipe manufacturers, and CT equipment manufacturers probably need to prepare for the same swings that the rest of the well-construction industry is used to.

Recommended additional reading at OnePetro: www.onepetro.org.

SPE 152351 Comprehensive Approach to Production Stimulation of Massive Cold Heterogeneous Carbonate Formation Using Coiled Tubing by Vladimir Dnistryansky, Schlumberger, et al.

SPE 154221 Production Logging on Coiled Tubing in a Marcellus Shale Horizontal Completion by A. McCluskey, Shell Exploration and Production

SPE 154060 Best Practices for Composite Plug Milling by Steven Craig, Baker Hughes, et al.

SPE 154423 Use of Coiled Tubing Deployed Expandable Technology in Sidetrack Drilling Operations by A. Caccialupi, Mohawk Energy, et al.
Coiled Tubing Reduces Stimulation Cycle Time by More Than 50% in Multilayer Wells in Russia
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 154386, ’Coiled Tubing Reduces Stimulation Cycle Time by More Than 50% in Multilayer Wells in Russia,’ by A. Yudin, SPE, K. Burdin, and D. Yanchuk, SPE, Schlumberger; and A. Nikitin, SPE, I. Bataman, A. Serdyuk, N. Mogutov, and S. Sitdikov, SPE, Rosneft, prepared for the 2012 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 27-28 March. The paper has not been peer reviewed.

Traditionally, coiled tubing (CT) has had very limited service diversity in Russia. Its use has been mostly limited to wellbore cleanouts and nitrogen kickoffs after fracturing treatments. CT equipment and technologies were used to supplement stimulation operations in one of the world’s largest oil fields, Priobskoye, which has up to five separate layers per well. Conventionally, well completions at Priobskoye have involved complicated workover operations with tubing, packers, and wireline perforation after each stimulated layer. An average well with three layers took 30 days to complete. CT provided a significant improvement in completion efficiency, reducing the cycle time to just 10 to 12 days.

Introduction

Priobskoye is one of the world’s biggest oil fields. It is in the Khanty-Mansi autonomous region, and the Ob river divides it into two parts, the left bank and the right bank.

Hydraulic fracturing is the main method used to increase production and recovery from the Priobskoye formations, and most new wells are stimulated immediately after drilling. Fracturing optimization has mostly evolved toward increasing the quality of hydraulic fractures. However, the Priobskoye field is a multilayer reservoir where separate fracturing treatments normally take excessively long times to complete. The standard completion method has consisted of a sequential approach of the workover crew perforating, the wireline crew running in tubing and packers, and the fracturing crew fracturing and pulling tubing and packers out of hole for each of the layers. That sequence takes a long time to complete the well, especially if the formation starts flowing naturally before the workover and wireline crews can manage the pressure properly to continue operations.

Starting in 2008, CT fleets were employed to assist in the well-completion cycle with abrasive perforating and well-cleanout operations under pressure between the fracturing stages. The advantage of CT lies in its ability to perform the same sequence of operations significantly faster. In fact, the CT replaced both workover and wireline rigs, with the perforating performed with an abrasive material jetted through the nozzles of a special bottomhole assembly. A jet’s velocity and its focused flow create a hole inside the casing and a cavern inside the cement and the rock outside the casing (Fig. 1).
Innovation: SPE Unveils a New Strategic Plan
Authors: Imomoh Egbert
Published: February 2015

President's column

By all objective measures, SPE is a very successful organization. Our membership, which has become increasingly global, has more than doubled in the past decade. The number of conferences and workshops has increased without compromising on quality. We’ve added new offices to serve our global membership. And we’ve added numerous new programs and services. We have managed our resources prudently and are financially healthy (see my article in last month’s JPT). But an organization that doesn’t periodically examine where it is going, especially in light of very rapid changes in the external environment, won’t remain successful.

In June 2012, the Board of Directors initiated a process to develop a new strategic plan for SPE. We gathered input from industry leaders, the Board, SPE members, and staff through a survey and interviews. This input framed the discussion at a Board workshop prior to the Annual Technical Conference and Exhibition last October, where we explored additional initiatives and discussed priorities. During the workshop, the Board confirmed that SPE’s mission statement correctly defines what we’re about, and it crafted a revised vision statement:

Enable the global oil and gas E&P industry to share technical knowledge needed to meet the world’s energy needs in a safe and environmentally responsible manner.

As part of the strategic planning process, the Board also considered the most significant threats to SPE’s continued success. The first threat has to do with oil and gas price volatility, which could affect support for SPE activities including membership and attendance at events. While SPE cannot influence the price of oil or gas, we can ensure that we are sufficiently prepared to withstand the impact of a price decline by making prudent investments and managing our costs. The second threat relates to concern that the quality of programs could be impacted by a rapid growth in SPE programs. To sustain our success, SPE must ensure that technical quality is not compromised. The third issue has to do with the changing demographics of SPE’s membership. More members are coming from areas that do not have a strong tradition of volunteerism. Coupled with the pending retirement of many of SPE’s long-time active volunteers, this could pose a significant challenge to SPE’s traditional volunteer-driven path to programming that must be addressed.
In Search of the Waterless Fracture
Authors: Rassenfoss Stephen
Published: February 2015

Waterless Fractures

The first hydraulic fracture experiment was waterless. A gasoline gel was injected into the Hugoton field in 1947. What was once an emerging technology in the US has become the growth engine for oil and gas production globally, and the napalm-based mix that was used then looks like an anachronism.

But fracturing using hydrocarbons is on the short list of options for the industry, which is looking for an effective substitute for water in hydraulic fracturing.

Environmental questions have arisen about water use and water quality in unconventional resource development, which requires millions of gallons of water per well to open path-ways for oil and gas trapped in nearly impermeable rock.

The Research Partnership to Secure Energy for America (RPSEA) has one waterless project in progress—to see if liquid nitrogen can fracture effectively—and the government/industry-funded research group is seeking more projects that experiment with waterless alternatives. “Water does work and has opened up the shale resources,” said Kent Perry, vice president of onshore programs at RPSEA. “(Fracturing) does take a lot of water. If you are in an area, particularly in parts of south Texas that are in a drought, even a little water is precious.”

Another driver for seeking waterless fractures is the search for a way to pro-duce more of the oil and gas out of the ground. Oil recovery in unconventional formations is generally well below that of conventional formations, with 3% to 6% estimated ultimate recovery rates in many unconventional oil formations.

“If you recover 10% (of the oil and gas), you are doing well but you are leaving 90% behind,” Perry said. “It is not just the fracture treatment. The whole approach will have to be looked at within those resources.”

Waterless fracturing could also remove an impediment to tapping unconventional formations in many spots around the world: limited water supplies. During a panel discussion at the recent International Petroleum Technology Conference, Peter Voser, chief executive officer of Shell Oil, said he “told the R&D group to come back with the waterless fracture.” His comment was delivered in Beijing, where Shell has been aggressively pursuing unconventional exploration opportunities in a country that has both enormous unconventional natural gas reserves and water shortages over large areas.
New Methods and Workflows Boost Effectiveness of Multizone Stimulation
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper IPTC 16865, ’Improved Methods and Workflows for Multizone Stimulation,’ by Kris Nygaard, SPE, ExxonMobil Production; Shekhar Gosavi and Pavlin Entchev, SPE, ExxonMobil Development; and Fuping Zhou, SPE, Wadood El-Rabaa, SPE, and Chris Shuchart, SPE, ExxonMobil Upstream Research, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.

Novel multizone stimulation technologies have enabled the development of tight resources that previously could not be developed economically and have enabled optimization of production resources distributed over thick gross intervals. These technologies are expected to become more broadly used for numerous applications worldwide because of their ability to rapidly place numerous stimulation treatments tailored to the specific needs of each zone, pump each treatment efficiently and effectively, and make more efficient use of equipment, people, and surface-site development.

Introduction

Unique stimulation challenges arise when hydrocarbon resources comprise multiple vertically distributed discrete reservoir intervals contained in long productive intervals or when targeting tight reservoirs with horizontal wells having extended lateral sections in reservoirs with significant heterogeneity. The overall challenge is characterized by the need to manage a balance between the number of stimulations performed, stimulation-treatment quality, cost, and the overall reliability of treatment placement and execution. Currently, managing this balance can result in operators intentionally bypassing less-attractive hydrocarbon intervals, incurring lower production because of poor stimulation effectiveness, labeling resources as uneconomic on the basis of the cost required to access the reserves, or having difficulty in achieving reliable and effective treatment placement. During the last decade, extensive research and field experimentation enabled the development of unique workflows, modeling capabilities, and stimulation methods for tight sandstone, shale, and carbonate formations.

Hydraulic-Fracture-Stimulation Design Methodology

The stimulation design methodology revolves around identification of the optimum completion scenario for the given reservoir conditions and local situation. Compared with conventional reservoirs, unconventional reservoirs with low matrix permeability, low porosity, and high water saturation may be more prone to damage and flow impairment.

Extensive field experience and measurements show the effective fracture volume is always less than the induced one. The rock is anisotropic and heterogeneous. In some cases, simple biwing-like fractures may be induced if the stress anisotropy is high; alternative fractures could be complex clusters with low anisotropic stress state. It is crucial to determine optimum completion scenarios, including horizontal longitudinal, horizontal transverse, or multizone vertical stimulations (Fig. 1).
Optimization of Limited-Entry Matrix Acid Stimulations in the Danish Central Graben
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 157429, ’Optimization of Limited-Entry Matrix Acid Stimulations With Laboratory Testing and Treatment Pressure Matching’ by Mary S. Van Domelen, SPE, and Mohamad abd Hammoud, Maersk Oil Denmark; Gerard Glasbergen, SPE, Shell; and Noor Talib, SPE, Maersk Oil Qatar, prepared for the 2012 SPE International Production and Operations Conference and Exhibition, Doha, Qatar, 14-16 May. The paper has not been peer reviewed.

In the Danish central graben, tight chalk reservoirs have been developed successfully through drilling, completion, and stimulation of long horizontal wells. These fields, developed since the early 1970s, are operated on behalf of a joint venture, the Dansk Undergrunds Consortium (DUC). One of the most successful technologies used in these fields is the controlled-acid-jetting (CAJ) technique.

Lower Cretaceous Formation, Central Graben

Fig. 1 shows the major producing fields of the DUC area. The Lower Cretaceous reservoir contains significant in-place oil volumes. Fig. 2 shows the thickness map of the Tuxen and Sola Lower Cretaceous formation in the central graben. This formation historically has posed a challenge to development because of its extremely low permeability; in addition, the formation is soft, highly heterogeneous, and has significant clay content in some areas. Thicker Lower Cretaceous reservoir sections in the Valdemar field have been propped-fracture stimulated successfully. Acid stimulation is preferred for the thinner sections; however, early attempts at matrix acid stimulation were very disappointing. Recently, the need to re-enter a well for maintenance allowed three zones to be selectively restimulated with improved execution techniques and a more appropriate acid formulation. Production increase following restimulation of this first well was very encouraging, and the lessons learned were applied to a second well.

The Lower Cretaceous formation is characterized by a high content of insoluble residue (IR), consisting mainly of clay with subordinate amounts of quartz, rare pyrite, and organic material. Porosity correlations were developed from core data and by petrophysical evaluation of logs. The porosity varies considerably, but is generally remarkably high. While the primary variation in porosity was linked directly to the IR content of the facies, factors such as pore pressure and depth of burial/compaction also had an influence.

On the basis of the formation core data, the Lower Cretaceous would not be considered a good candidate for matrix acid stimulation. It is well established, however, that low-permeability reservoirs can be economically produced by long, horizontal wellbores that effectively maximize reservoir contact.
Technology Focus: EOR Operations (June 2013)
Authors: Bonet-Cunha Luciane
Published: February 2015

Technology Focus

Enhanced oil recovery (EOR) operations are designed to follow deterministic and detailed procedures, with planned actions for the people executing them and expected reactions from the system (reservoir) to which operations are being applied. However, a number of hurdles need to be overcome to reach a successful action/reaction, problem-free status in EOR operations. One challenge is that success depends on insightful subsurface knowledge. Nevertheless, as is well-known to people in the oil industry, information about key reservoir properties is scarce and limited to point measurements inside the wells and nondestructive remote data at much lower resolution. Thus, there is great uncertainty in the process of describing the reservoir, and EOR operations must be planned, developed, and managed in this uncertain environment. To reduce uncertainty, the strategy should be to focus at first on a robust EOR screening and design process, gathering as much reservoir data as possible. In the second stage, technically sound pilot studies can increase knowledge and reduce operating risk.

Time and resources spent on those two topics have provided oil operators with improved EOR-management techniques, despite the underlying reservoir uncertainties, with fewer surprises and less stress and ambiguity. Like a gold-medal team in a synchronized swimming event, despite participants being outside their natural and well-known environments, training and teamwork are responsible for a unique, precise, and quite deterministic result.

The papers featured this month will give you only a few examples of the vast amount of high-quality material that was published last year and will illustrate how EOR operations, though challenging, can be tackled on the basis of technological advances in data acquisition and careful analysis and interpretation of reservoir data during screening and pilot-study phases. I hope you will enjoy the reading and will search for additional papers in the OnePetro online library.

Recommended additional reading at OnePetro: www.onepetro.org.

SPE 164048 Novel Scale Remediation for Steam-Assisted-Gravity-Drainage Operations by Timothy Cheung, Shell Canada, et al.

SPE 155123 Industrial Experience in Seawater Desulfination by Pierre Pedenaud, Total, et al.

SPE 157996 Optimizing Water-Injection Rates for a Waterflooding Field by Feilong Liu, Chevron Energy Technology Company, et al.

SPE 159620 A New Approach To Deliver Highly Concentrated Surfactants for Chemical Enhanced Oil Recovery by Julian Barnes, Shell Global Solutions
Albacora Subsea Raw-Water Injection
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 24167, ’Albacora Subsea Raw-Water-Injection Systems,’ by L. Buk Jr., C.A. Andrade, J.B. Azevedo, E.J.J. Coelho, O.C. Costa, C. Kuchpil, A.G. Siqueira, and A.L.S. Souza, Petrobras, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed.

To increase the oil recovery in the Albacora field, significant water injection is required that was not considered in the initial project-development phases. Technical and economic constraints do not allow the use of conventional seawater-injection plants because current production units have no area available to implement a conventional water-injection system. Application of subsea raw-water-injection (SRWI) systems in the field involved challenges that required a detailed and systematic analysis to evaluate the technical feasibility and establish requirements for implementation. This alternative enabled seawater to be injected into the reservoir with minimum treatment by use of equipment installed on the seabed.

Introduction

In some offshore fields, mainly mature fields, the addition of conventional technologies to topside facilities can constrain the use of seawater injection. Conventional systems require the installation of too many pieces of equipment at the production units, which requires large areas that sometimes are not available. Other restrictions include swivel constraints on floating production, storage, and offloading vessels (FPSOs) and load limitations.

One alternative is SRWI technology in which most of the system is installed at the seabed and seawater is injected with minimum treatment. This system has minimal effect on the topside- facilities footprint. The SRWI alternative involves technical challenges that include seawater compatibility with the reservoir rock and fluids, microbiological control, corrosion, water properties, reliability of the subsea equipment, and power, which limit the use of this technology in some scenarios.

Petrobras established a project to evaluate and develop this technology, involving technical-feasibility studies and evaluation of various scenarios and preliminary specifications. During this project, Albacora-field reservoir studies indicated the need for large amounts of water injection, and SRWI became the only economically feasible alternative identified to address this demand. 

Albacora Field

Albacora is a giant field in the Campos basin, approximately 100 km offshore Brazil, covering an area of approximately 235 km2, with water depths of 250 to 1100 m. The field was discovered in September 1984 and has an estimated oil-in-place volume of 4.4 billion bbl. Pilot-phase production started in 1987 with the FPSO P.P. Moraes. In 1993, a second development phase started with the semisubmersible P-24, which was replaced later by the definitive production system with two production units: the semisubmersible P-25 and the FPSO P-31, installed in 1996 and 1998, respectively. Field oil production peaked in 1999.
EOR: Next Frontier for Unconventional Oil
Authors: Joshi Sada
Published: February 2015

Guest editorial

Recent headlines declared that the United States could end net oil imports by 2037. That finding, by the US Energy Information Administration (EIA), is the agency’s first-ever projection—albeit under a high-resource scenario—of possible oil self-sufficiency for America.

It is a stunning reversal of a trend. US net oil import dependency was at 60% as recently as 2005 and thought to be headed to 70% within a decade. Instead, today it is about 33% and dropping.

Many of my colleagues in the oil and gas industry and I have long believed that achieving such a milestone was possible, if only the right combination of technology, economics, and political will could come together. We understood the scope of the vast untapped hydrocarbon bounty in the US, recognizing that half of its identified oil endowment of nearly three-quarters of a trillion barrels of oil is untapped. That is why the US leads the world in the application of improved oil recovery (IOR) and enhanced oil recovery (EOR) technologies.

Much of the credit for the surge in US oil production goes to the advances in horizontal drilling and hydraulic fracturing applied to massive shale and other tight oil rock formations. Indeed, even under the EIA’s reference case, shown in Fig. 1, tight oil sustains overall US production for many years at a level nearly twice what expectations were just a decade ago. Both technologies essentially qualify as IOR, bolstering the claim that, in fact, IOR is responsible for America’s energy revolution.
Carbon Capture: Saudi Aramco's Carbon Management Program
Authors: Al-Meshari Ali A. , Muhaish Fahad I. , Aleidan Ahmed A.
Published: February 2015

Carbon Capture

Many industries are doing their fair share to address climate change and combat greenhouse gas (GHG) emissions. For the oil and gas industry, meeting global and domestic energy demands while addressing climate change presents numerous challenges but also opportunities. With the unprecedented level of international attention on climate change in recent years, Saudi Aramco is keen to play a leading role in addressing the main issues.

Technological solutions, such as advanced and highly efficient hydrocarbon technologies and carbon capture and storage (CCS), are key elements to addressing climate change rather than aiming at dispensing of fossil fuels in a world of global interdependence. Almost all scenarios indicate that the world will continue to depend on hydrocarbon- based energy sources for the foreseeable future. It is therefore prudent to adopt collaborative hydrocarbon research and develop solutions for CO2 geological sequestration, subsurface utilization of CO2, cost reduction for CO2 capture from fixed sources, and explore new technologies to increase efficiency and reduce CO2 emissions from mobile sources.
Acidizing a Sandstone Formation Successfully in the Gulf of Cambay
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164631, ’Overcoming Challenges While Acidizing Sandstone Formation Successfully in the Gulf of Cambay, Offshore India,’ by Sergey Stolyarov and Anwar Alam, Baker Hughes, prepared for the 2013 SPE North Africa Technical Conference and Exhibition, Cairo, 15-17 April. The paper has not been peer reviewed.

This paper describes a matrix-acidizing campaign executed successfully in the Gulf of Cambay on the west coast of India. In initial laboratory tests and during simulation runs, the goal was to design a preflush/ acid/post-flush system to best suit challenging reservoir conditions while also considering offshore logistics. After pumping the system in one well, the system design, pumping procedures, and volumes were modified to improve results further in the next well.

Introduction

The offshore field, located in the Arabian Sea off the western coast of India, has been on production since 1997 (Fig. 1). The field covers an area of 1471 km2 and lies 160 km north/northwest of Mumbai. The reservoir consists of a stacked series of sands deposited in the Lower Miocene and Oligocene. The field has up to 13 different Olio-Miocene gas-bearing sands separated by shales. Reservoir-sand permeability ranges from 100 md (in shaly beds) up to 5,000 md in clean sand beds. Because of the unconsolidated nature of the reservoir sands, gravel-pack screens are a typical well completion in the field.
Technology Focus: Wellbore Tubulars (June 2014)
Authors: York Pat
Published: February 2015

Technology Focus

NORSOK (the competitive standing of the Norwegian sector), as most know, is the industry initiative to add value, reduce cost and lead time, and eliminate unnecessary activities in offshore field developments and operations.

The NORSOK-010 Rev. 4 Standard document defines requirements and guidelines regarding well integrity in drilling and well activities. It defines well integrity as the “application of technical, operational, and organizational solutions to reduce risk of uncontrolled release of formation fluids throughout the life cycle of a well.” The NORSOK standard focuses on establishing well barriers by use of well-barrier elements in conjunction with their acceptance criteria, their use, and monitoring of integrity during their life cycle. Further, it defines a well-barrier element as a physical element that in itself does not prevent flow but, in combination with other well-barrier elements, forms a well barrier.

The standard focuses strongly on the establishment of well barriers and well-barrier elements and on how these are accepted and monitored to prevent loss of well integrity that ultimately could lead to a loss in wellbore-fluid containment. The general principle of the two-barrier concept is that two well barriers should be in place at all times to ensure the provision of well integrity. In the drilling phase, the primary well barrier is typically the fluid column. Secondary well-barrier elements can be the in-situ formation, casing cement, casing, wellhead, high-pressure riser, or drilling blowout preventer.
Liner-Drilling Technology Mitigates Lost Circulation Offshore Mexico
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 163418, ’Use of Liner-Drilling Technology as a Mitigation for Lost Circulation in the Faja de Oro (Golden Lane) Oil Fields Offshore Veracruz, Mexico,’ by L.F. Aguilera Naveja, Pemex, and Steven M. Rosenberg, SPE, and Marco A. Dominguez M., SPE, Weatherford, prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5-7 March.

This paper will demonstrate the benefit of liner-drilling technology used to drill and cement an operator’s 9?- and 7-in. liners in place, allowing for the continued development of oil reserves in the Carpa and Bagre fields of the Faja de Oro area offshore Veracruz, Mexico. Before the introduction of drilling-with-liner (DWL) technology, two previous wells drilled in the Carpa field encountered massive lost circulation and hole instability while drilling into the El Abra limestone, resulting in a total of 55 days of nonproductive time (NPT) for the two wells.

Introduction

Nine fields have been developed in the offshore Faja de Oro area of the Gulf of Mexico (Fig. 1). They are the Arrecife Medio, Isla de Lobos, Tiburon, Bagre, Atun, Morsa, Escualo, Marsopa, and Carpa fields, and to date the estimated cumulative production is some 210 million BOE of light crude ranging from 30 to 40°API from the El Abra Middle Cretaceous limestone.
Conversations: You Must Be the Change
Authors: Fattahi Behrooz
Published: February 2015

President's column

The aging of our industry’s workforce and the near-term disappearance of the related knowledge base and experience are apparent when examining the data on SPE members’ age distribution (excluding student members).

Fig. 1 shows that the “big crew change” is well under way with the Baby Boomers* preparing to leave our industry. It is estimated that the potential outflux in the next decade will be as large as 50% of those who are currently employed in the industry. The chart also shows a developing second peak where Generation Y* enters the industry in recent years, with a low for the Generation X* segment of the workforce.

Our industry lost a generation of workers in the 1980s, and now it is obvious that the rate of skills replacement is not adequate. Demographics in other sectors are similar to SPE’s. Charles Davidson, the CEO of Noble Energy, says, “There are about three per cent of the American Association of Petroleum Geologists members who are around 80 years old, and we may be needing them!” (Rhodes 2007). To sustain a planned expansion in investment estimated at USD 200 billion over the next 15 years, the industry is poised to recruit a large number of new talent. According to Lee Hunt, president of the International Association of Drilling Contractors, just the offshore rigs currently under construction will require an additional 17,000 new people not currently employed in our industry (Duey 2008). This talent squeeze can slow down the industry’s growth.

The current economic downturn has only delayed the wave of retirements and has resulted in a slowdown in hiring that may have somewhat masked one of the most significant challenges facing our industry today—inspiring talented young people to join the industry and prepare to lead it into the future.

*Baby Boomers are those born in the mid 20th Century, following World War II. Generation Y is the group born during the period 1976–95.   Generation X is roughly defined as those born during 1965–80.
Comments: Assessing the Spill
Authors: Donnelly John
Published: February 2015

Editor's column

As the Deepwater Horizon disaster drags on, the oil and gas industry is trying to offer some perspective around what has become a politically charged incident.

During last month’s International Oil and Gas Conference and Exhibition in China in Beijing, the incident, its cause, and its implications came up several times in the hallways and during panel sessions. During the executive plenary session, several top executives offered their thoughts on the accident.

The spill will “go down as a very dark moment,” for the industry, said Matthias Bichsel, a member of the Executive Committee of Royal Dutch Shell and director of Projects and Technology for Shell International E&P, adding that the loss of life in the accident was the biggest tragedy. The industry has a strong track record of conducting deepwater operations safely and the processes and the technology are in place to continue that record. “We need to learn what happened, then fix what needs to be fixed,” he said.

Mark Albers, senior vice president of ExxonMobil, said it was “premature” for governments to rush toward more regulation because no one is sure exactly what happened yet. The oil and gas industry has drilled 14,000 wells in deep water, including some more challenging than the one that was the source of the accident. The fundamental question for the industry is to find the root causes of the accident and determine if there was something unique about this well that would lead to an adjustment in best practices, he said.

Andrew Gould, chairman and chief executive officer of Schlumberger, agreed that it is too early to assess what happened or what needs to be done. But he noted that the industry should work on uniformity of deepwater project planning and contingency planning. There are operators of different sizes operating offshore and the quality of project planning for deepwater projects varies, he said. The industry must “self-discipline” itself or be open to more regulation, he added. One unfortunate aspect of the accident is that it could make it more difficult to attract young people to the industry, Gould said.

Behrooz Fattahi, 2010 SPE president, has noted that many SPE members have inquired about the spill. “SPE will have a role to play in addressing technical issues resulting from the accident; however, SPE is not the right organization to deal with a short-term emergency response,” he said in a statement, adding that there already are a large number of qualified people from the industry who are working to resolve the situation. “SPE’s mission is sharing technical knowledge, and our strength is in providing a longer-term response. We help the industry to learn from incidents like this, and will serve an important role in providing a forum for discussions on changes needed in equipment, operating practices, training and other recommendations on how to prevent or reduce the impact of future oil spills.”