bluuebunny/crossref_metadata_2025 huggingface dataset:
Passive Inflow-Control Device Maximizes Productivity Through Every Phase of a Well's Life
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 13863, ’The First Passive Inflow-Control Device That Maximizes Productivity During Every Phase of a Well's Life,’ by Luis A. Garcia, SPE, Martin P. Coronado, SPE, Ronnie D. Russell, Gonzalo A. Garcia, SPE, and Elmer R. Peterson, SPE, Baker Hughes, prepared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December. The paper has not been peer reviewed.

In long horizontal wells, production rate typically is higher at the heel than it is at the toe. This imbalanced production profile may cause early water or gas breakthrough into the wellbore. To eliminate this imbalance, inflow-control devices (ICDs) are placed in each screen joint to balance the production-influx profile across the entire lateral length to compensate for permeability variations. Passive ICDs (PICDs) could control the influx without the need for intervention.   

Introduction

The primary purpose of ICDs is balancing well production throughout the operational life of the completion to optimize hydrocarbon recovery. Because a typical well with ICDs can produce for 5 to 20 years or longer, the long-term reliability of such a device is crucial to the well’s overall success. If an ICD cannot maintain a uniform flux rate, increased localized production rates will occur and the well will become unbalanced. Thereby, the ICD becomes ineffective, leading to premature water and/or gas breakthrough and possible loss of sand control. Water can reach the wellbore in certain sections because of formation heterogeneities and/or vertical fractures. Ideally, once breakthrough occurs, flow contribution from these water-producing zones should be less than that of the oil-producing sections. The ICD device should increase the flow restriction at the onset of water production, thus allowing other oil-producing zones to continue flowing effectively. In wells with oil viscosity >10 cp, ICD-type selection becomes more critical because of the large difference in viscosity between the oil and produced water. To maintain an even flow profile across the entire wellbore lateral, the pressure-reduction mechanism in the ICD situation must have the lowest sensitivity to viscosity. A restrictive-type ICD can provide desirable results in this regard with its lower sensitivity to viscosity. However, this type of ICD requires a very small flow area to generate the pressure drop (restriction) required in ICD applications. This small flow area has a greater potential for erosion and a low plugging resistance.

Another solution is to enable lower viscosity sensitivity in the restrictive device with the low erosion and high plugging-resistance level of the frictional design. The restrictive-pressure-loss mechanism can be used while limiting the fluid velocity through the device below the critical level, which will minimize erosion potential.
Technology Focus: Drilling Management (September 2010)
Authors: Cunha J.C.
Published: February 2015

Technology Focus

Certainly there is not a single JPT reader that has not already read and heard about the Macondo-well blowout in the Gulf of Mexico (GOM). Over the last few months, this accident has been present in almost every conversation about the oil industry. Many articles have been written, and many more certainly will be prepared and presented at future conferences. The subject has been present in the daily media around the world. In the SPE Drilling and Offshore Operations technical interest groups, several posts have generated heated discussions as well as a diverse array of propositions about how our industry should proceed from now on. So it seems natural that this JPT section dedicated to drilling management also should address the subject.

For those of us working in the GOM area, it is more than clear by now that this accident will change the industry forever; and not only in the GOM. Members of the industry, managers and technical experts alike, are taking this occasion to reassess operational procedures, equipment safety, and training needs to find opportunities for improvement that will make our operations safer and more efficient. A proficient drilling-management process is now more important than ever. This process must permeate all phases of a project, from early planning to final execution. Risk assessment of all operations must become a routine.

Last year, I wrote in this space about the importance of risk management for drilling and completion operations. I mentioned that there are many articles concerning successful projects in which risk analysis was a fundamental part of all operations. Now may be the right moment for all of us to follow those engaging examples. At the risk of being repetitive, I would like to conclude with exactly the same words that I used to close last year: “It is clear to me that drilling management is related closely to risk management. The correct assessment of all risks involved in drilling operations will provide better planning and consequently will improve operational results.”

Drilling Management additional reading available at OnePetro: www.onepetro.org

SPE 128288 • “Drilling Efficiency and Rate of Penetration—Definitions, Influencing Factors, Relationships, and Value” by Graham Mensa-Wilmot, SPE, Chevron, et al.

SPE 128222 • “High Performance and Reliability for MPD Control System Ensured by Extensive Testing” by John-Morten Godhavn, SPE, Statoil, et al.

SPE 128871 • “Real-Time Drilling-Data Analysis: Building Blocks for the Definition of a Problem-Anticipation Methodology” by R.A. Gandelman, Petrobras, et al.
Interview with 2013 SPE President Egbert Imomoh
Authors: Donnelly John
Published: February 2015

President's interview

Egbert Imomoh, the nonexecutive chairman and a cofounder of Afren, a Pan African independent oil and gas company with assets in Africa and Kurdistan, is the 2013 SPE president. He will take office during the 2012 SPE Annual Technical Conference and Exhibition in October in San Antonio. 

Imomoh joined the oil and gas industry in 1968, working with Shell in Nigeria as a petroleum engineer after basic training in the Netherlands. He worked in Nigeria, the UK, and the Netherlands and rose to the position of deputy managing director of Shell Petroleum Development Company of Nigeria, a position he held until his retirement in February 2002. After that, he worked with Shell International in London as a senior corporate adviser on Nigeria during 2002–04.

Imomoh helped found Afren in 2004 and served as its managing director and executive chairman before assuming his current position. He led the growth of Afren’s Nigerian asset base, established a number of successful indigenous partnerships, and led the company to achieve its first oil milestone at the Okoro Setu project.

He has been a member of SPE since 1973 and was a founding member of the SPE Nigerian Section. He was chairman of SPE Nigeria Council in 1986 and was named a Distinguished Member of SPE in 1999. Imomoh served as the first regional director for Africa on the SPE Board of Directors between 2000 and 2003, and was the chairman of the Board Committee on Educational and Professional Activities during 2002–03. He has been chairman of the Board of Trustees, SPE Nigeria Council, since 2007. Imomoh was named an SPE Honorary Member, the highest honor that SPE presents to an individual, this past year.  Imomoh graduated with a BS degree in mechanical engineering from the University of Birmingham, UK, and received an honorary Doctor of Science degree from the University of Port Harcourt this year.

You served on the SPE Board of Directors during 2000–03. Coming back to the board as president now, have you observed any changes in SPE during the intervening years?

Over the years, SPE has become even more international, increased its membership, and has continued to seek ways to serve its members better by organizing many more conferences and workshops, starting up new publications, and by creating regional offices to move its services closer to our members.

SPE’s membership—now more than 100,000—has continued to grow even as other associations lose members. To what do you attribute this success?

Our success can be attributed to a number of reasons. The board and staff have always focused on member needs; they foresaw the need to attract young members and created a student membership program that took off like a rocket. Our technical information offerings have continued to grow and, where necessary, we have formed partnerships with other associations that have strengthened our ability to deliver first-class technical programs at very competitive pricing.
Oil Sands Get Wired - Seeking More Oil, Fewer Emissions
Authors: Rassenfoss Stephen
Published: February 2015

Heavy oil technology

Two projects in Canada are out to show that oil sands production need not remain in the steam age. Both are powered by electricity, though they use it quite differently. The motivations are the billions of barrels of crude in formations where current methods are not practical or economic, and a desire to find a way to produce heavy crude with less energy and water.

No one is talking about replacing steam for heavy oil production—it is an extremely efficient method for delivering the heat needed to reduce the viscosity of the heavy crude called bitumen. But the potential payoffs for finding a workable alternative is huge.

Of the total bitumen resource in the ground in Alberta, 7% is shallow enough to be mineable, said Todd Zahacy, senior engineering consultant for exploration and production at C-FER Technologies. While production using in-situ extraction techniques from deeper reserves has recently exceeded the output from mining, only about 9% of that vast resource is counted as reserves in Alberta’s 2012 survey of its oil, gas, and coal resources. “There is a massive prize out there if you can go after those areas that are not currently technically producible,” said Zahacy, with the research and testing company that has been evaluating electric methods for a client.

The goals of these two programs are electric-powered heating methods capable of eliminating the costly equipment needed to produce steam and process large volumes of water on site. Lower-temperature methods may also reduce energy use and open up access to underground formations not suited for high-pressure steaming.

The search for electric-powered heating in heavy oil fields goes back decades, but no one has made it work on a commercial scale. Les Little, executive director of energy technology for Alberta Innovates, has long followed the experiments with electric heating technology, and he knows many question if it can be more successful this time. The government technology promotion agency is backing another round of testing, though, because he said this technology “is not your dad’s electrical heating system.”

The province is putting up more than USD 23 million from the Climate Change and Emissions Management Corporation—the government arm is funding half the budgeted cost—because the two electric-powered heating projects could reduce the environmental impact of heavy oil production as measured by water use and carbon dioxide emissions.

That is a potent motivation in Alberta. Projects critical to tapping the oil sands, such as the Keystone pipeline running from western Canada to US Gulf Coast refineries, have been threatened by environmentalists who point out the energy and water required for heavy oil extraction mean it has a larger environmental impact than conventional production.
Virtual-Measurement Value During Startup of Major Offshore Projects
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 14518, ’Virtual-Measurement Value During Startup of Major Offshore Projects,’ by R. Cramer, SPE, N. Griffiths, P. Kinghorn, SPE, and D. Schotanus, Shell Global Solutions; John Brutz, SPE, Shell USA; and Klaus Mueller, SPE, Shell Oman, prepared for the 2011 International Petroleum Technology Conference, Bangkok, Thailand, rescheduled to 7-9 February 2012. The paper has not been peer reviewed.

How can wells be managed optimally if one does not know continuously what they are producing? This problem is more critical at initial startup of the wells. Shell uses a real-time well virtual-flow-measurement tool, running on 60% of Shell’s global production, which has enabled significant added value in the areas of real-time surveillance and optimization. The virtual-flow-measurement tool has been applied in the startup of several of Shell’s offshore projects in the Arabian Gulf and in the Gulf of Mexico.

Introduction

Shell has several large upstream offshore projects in various stages of startup or commissioning. These projects have large capital investments and reserves contribution and a high degree of difficulty (e.g., very deep water, subsea processing, long subsea multiphase pipelines, and feeding large onshore gas plants). Hence, it is imperative to start up the processes as quickly and efficiently as possible, yet maintain the highest possible standards of technical integrity, safety, and environmental effects. Key aspects for efficient and effective project startup are well and reservoir surveillance and hydrocarbon accounting. It is important to know how much the wells are producing and the composition of the fluid streams to maximize production and for flow assurance, asset technical integrity, and accounting purposes. Ideally, this would be achieved by use of multiphase flowmeters (MFMs) on each well to measure the oil, gas, and water flows physically and continuously, or by routing each well progressively to a test separator as the wells are started up. However, at the time of startup, MFMs may not have been installed for all wells, and for wells that do have them, they usually are not yet commissioned because MFM commissioning requires fluid samples from the wells, and for subsea wells, sampling usually is performed robotically and at a later stage of startup. Virtual flow meters (VFMs) can be operational when production begins. Similarly, test separators may not be commissioned at the time of initial well production, and if they are operational, they are not suitable for tracking production from multiple wells. Hence, virtual flow measurement has significant value for well/reservoir surveillance and hydrocarbon accounting from initiation of startup to the time when MFMs are effectively commissioned and, thereafter, as effective insurance in case of individual-meter failure.
Discussion/Reply: Downhole Steam Generation Pushes Recovery Beyond Conventional Limits
Authors: Jones Jeff , Capper Laura , Kuhlman Myron , Vassilellis George , Schneider M.J. , Fitzpatrick Nick
Published: February 2015

Discussion/Reply

The authors of paper SPE 150515, titled “Downhole Steam Generation Pushes Recovery Beyond Conventional Limits,” (JPT June 2012), are commended for bringing the topic to the forefront. However, the article is a little too optimistic and may lead the reader to wrong conclusions. With all the perceived promise over the decades, this technology is still in the conceptual stage, especially in the reservoir EOR mechanisms envisioned by the authors and in the basic operational design.

Playing devil’s advocate, here is a short list of possible “cons” to accompany the article’s list of “pros” for the process:

Conventional steam-enhanced oil recovery (EOR) depends on the latent fraction of heat contained in quality steam. Sensible heat in water has proven to be of little help in the recovery of incremental oil. For the typical project that operates at <<100 psig, the latent fraction of heat in the steam is in the range of 80%. For steam at the proposed >2,000 psig the latent fraction falls to about 35%. If applicable, this changes the mechanism displacing oil from the reservoir; it is no longer a conventional steamflood.

In general, the deeper the reservoir, the hotter the formation. The hotter the formation, the lower the oil viscosity and less need for steam. In California, the typical reservoir at 2,000 ft is 130°F and at 5,500 ft, it is 200°F. Granted, other parts of the world have lower temperatures at depth (e.g., the Alberta fields are about 130°F at 5,000 ft); however, this is a limiting factor for deep thermal processes.

Deeper reservoirs tend to be tighter sands and the downhole steam generation (DHSG) demands that all the fluid sent downhole is injected. This will require either reduction of injection, which has implications for the reservoir process, or injecting at fracture pressures, which has its own set of problems.

There are few better filters in the oil field than a wellbore sand face. Couple this with the inevitable particulate generation in DHSG, and well plugging problems are likely to occur.
Comments: Looking Ahead
Authors: Donnelly John
Published: February 2015

Editor's column

Initial forecasts for 2014 predict continued growth in global oil supply, relatively moderate demand, and a potential softening of oil prices. International events could change that picture overnight but, for now, the industry’s three leading forecasters—the International Energy Agency (IEA), the US Energy Information Administration (EIA), and OPEC—are in agreement about what to expect next year.

The boom in oil production—primarily from North American unconventionals—should lead to another year of global surplus, with supply outstripping world demand. Global demand will actually rise next year, but at a lesser rate than non-OPEC oil supply. In addition to the US, supplies are expected to increase from Canada, Brazil, and Kazakhstan. ExxonMobil’s Kearl project will boost Canadian output, while the startup of the Kashagan project in the Caspian Sea should add 250,000 BOPD in production in Kazakhstan.

The IEA believes that non-OPEC output will rise by 1.3 million BOPD next year, annual growth that has occurred only once in the past 20 years. The largest increase will come from the US, with that country’s production rising 500,000 BOPD. In July, US crude production increased to 7.5 million BOPD, the highest monthly level of production since 1991. The EIA forecasts that US total crude oil production will average 7.4 million BOPD this year and 8.2 million BOPD in 2014.

Total global demand is forecast to rise 1.3 million BOPD next year, to more than 90 million BOPD, according to the IEA, with OPEC slightly less optimistic with a forecast of a 1 million BOPD rise. Global oil demand has grown approximately 7 million BOPD since 2005. OPEC member countries will meet in December to formalize strategy for 2014.

Meanwhile, OPEC is coming to grips with the US shale boom. At its meeting in July, OPEC ministers conceded that the world will need less of its crude even though world demand will grow at its healthiest pace since 2010. The organization said that demand for OPEC crude will fall by 300,000 BOPD to 29.6 million BOPD. Production from OPEC leader Saudi Arabia is healthy, as output has grown to historic levels. 

Differences exist among these three major forecasts. The EIA is more optimistic about global demand and supply growth while OPEC is the most pessimistic. All three forecasters predict that OECD demand will decline, although at a slower rate, while non-OECD demand growth will continue to increase. China is something of a wild card. The EIA predicts a slight rise in Chinese demand growth next year to 389,000 BOPD from 360,000 BOPD this year. But OPEC sees that demand growth relatively flat.
Top Trends in the Oil and Gas Sector
Authors: Karev Adi
Published: February 2015

Management

The past 12 to 18 months witnessed the oil and gas sector drifting away from the rule of certainty and the return of uncertainty. Uncertainty required more focus, deeper analysis, and operational determination. Deloitte’s fourth annual Oil & Gas Reality Check identifies five trends and delves into the fundamental characteristics of each trend: the supply, demand, macroeconomic, regulatory, cost, price, and competitive behavior factors.

Given the rise of shale gas resources and with new countries entering the ranks of net energy exporters, some are proclaiming that a global revolution is at hand with fundamental shifts in energy geopolitics because of newly found energy independence. A closer examination of the development progress of countries with major shale gas resources reveals a vastly different picture. Countries that can commercially produce unconventional and conventional gas seek higher returns by exporting or planning to export liquefied natural gas (LNG) to Asia Pacific countries that have historically agreed to long-term purchase contracts at oil indexed prices. The expected increase and diversity of LNG supply is spurring transition away from oil price indexation, and the rise of gas hub and hybrid price indexation.

The discovery of new resources across various geographies coupled with the technical challenges of developing those resources are softening governments’ resource policies—an indicator of the degree of resource nationalism. As production efficiency rates and capabilities improve, will resource national-ism surge or will it pale in comparison with the competitive rise of national oil companies (NOCs)? How companies react to and deal with this uncertainty is changing the notion of a singular business model and giving rise to different business models.

Each of these questions and the five trends are discussed below:

Shale gas: A global or regional resource?

The success of North American shale gas has created interest in duplicating the results in other countries. An April 2011 study by the US Energy Information Administration estimated that world shale technically recoverable resources outside the United States were 5,760 Tcf, sparking widespread interest in international shale. However, the presence of shale gas in the ground does not guarantee the unearthing of a fortune.
Instilling Realism in Production Forecasting Decreases Chances of Underperformance
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 155443, ’Instilling Realism in Production Forecasting: Dos and Don'ts,’ by Avnish K. Rajvanshi, SPE, Robert Gmelig Meyling, and Danny ten Haaf, SPE, Petroleum Development Oman, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8-10 October. The paper has not been peer reviewed.

Across the exploration-and-production (E&P) industry, several projects were found to underperform compared to the promises made at the time of project approval. Investment decisions on upstream projects rely, to a large extent, on the robustness of the predicted ultimate recovery and production forecast associated with the chosen development concept. The challenge for the E&P industry is to ensure that project approvals are based on realistic forecasts. This paper is intended to increase awareness among the forecasters and the decision makers about pitfalls associated with production forecasting.

Introduction

Recently, an industry benchmarking consortium concluded the sixth of a series of long-term production-attainment studies, which reviewed the production profiles of 59 major development projects from different hydrocarbon-producing regions. For the majority of projects, the forecasted production was not achieved.

Long-term production forecasts drive company strategies, portfolio choices, sales contracts, and shareholder promises. Too-optimistic forecasts result in underdelivery of projects, with often far-reaching consequences. Too-pessimistic forecasts, on the other hand, may lead to undervaluation of assets.

The value of an E&P company is determined by the projects in its portfolio. Some projects in the portfolio are mature, with a high likelihood of progressing to the execution phase. Some projects are immature, with a possibility of not reaching the execution stage (Fig.  1). For each project, it is important to have a realistic expectation of costs and production because this is the basis for business decisions. In addition, for immature projects, it is equally important to estimate the likelihood that they will be executed. At the portfolio level, this probability of maturation will lead to an appropriate expectation of expenditure and production and will facilitate the making of higher-level business decisions. Fig. 2 shows how to combine realistic forecasting at the individual-project level and at the portfolio level.

Pitfalls of Production Forecasting

Despite considerable efforts to prepare production forecasts, gaps between the forecast and the actual production are found in the majority of cases. Analysis of these gaps for a large number of E&P projects led to the following generic issues.
Conformance Control and Proactive Reservoir Management Improve Deepwater Production
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper IPTC 16702, ’Deepwater Production Improvement Through Proactive Reservoir Management and Conformance Control,’ by Rahim Masoudi, SPE, Hooman Karkooti, SPE, Shlok Jalan, SPE, Anndy Arif, Keng S. Chan, SPE, and Mohamad B. Othman, SPE, Petronas; and Steve Burford and Philip Bee, Murphy Sabah Oil, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.

The K field is one of the more developed deepwater fields currently going through development in Malaysia. It has an excellent data set from which to optimize future development activities. In hindsight, it is clear that much more complexity exists than initially thought. As a result, uncertainty does not necessarily diminish at the start of production and a comprehensive collection and analysis of dynamic performance data are required in order to optimize recovery further.

Field Background and Geological Setting

The K field is a deepwater development located in 1330-m water depth offshore Sabah, Malaysia. The field was discovered by the K-1 well drilled to a depth of 3600 m on 30 July 2002 and marked the start of deepwater development in Malaysia. Five years after first oil, the field has more than 30 active wells including producers and injectors.

The K field is located in Block K (Fig. 1) and comprises the outbound tract of a major northwest/southeast-trending foreland fold-thrust belt that extends from Brunei to the Philippines and forms the margin of the North Sabah trough. Block K is dominated by fold-thrust structures. The reservoir section of the K field is dominated by mass-transport deposits with interspersed complex reservoir-bearing turbidite deposits.

Subsurface Development Challenges

The deepwater fields under development and study phases in Malaysia are usually considered to have more or less similar subsurface complexities and uncertainties. Among these uncertainties are level of heterogeneity, thinly-bedded-to-blocky sands, compartmentalization, fault intensity and behavior, reservoir connectivity, pressure and flow communication across the field, injection requirement from early production time, sand/fines production and reactive shale, wellbore stability, and commonly inadequate available data at the time the development decision is made.

The typical type log in the K field shows the reservoir has been subdivided into eight distinct reservoir packages labeled H110 through H150. In this ex-ample, the gross reservoir thickness (h) is 492 m with a net sand thickness of 50 m, giving an overall net/gross ratio of 0.102. Apparent from the type log is a large percentage of thinly bedded reservoirs, characterized to be beds that are less than 30 cm thick.
Advancements in Completion Technology Increase Production in the Williston Basin
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 159586, ’Advancements in Openhole-Completion Technology Increase Efficiencies and Production in the Williston Basin,’ by John Paneitz, Whiting Petroleum, and C. Christopher Johnson, Matthew White, and George Gentry, Baker Hughes, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8-10 October. The paper has not been peer reviewed.

Over the years, hybrid systems have been installed in horizontal wellbores to increase the number of compartmental sections for hydraulic fracturing because of the limitations of ball-actuated fracture sleeves. Experimenting with hybrid systems provides operators with the ability to optimize spacing of fracture stages along the horizontal section when sleeve technology alone does not allow for the desired number of stages. The costs are higher for operators to perform a hybrid-type completion, however, and this has driven enhanced sleeve technology to allow for all-sleeve completions.

Introduction

The Bakken shale located in the Williston basin covers an area that includes portions of North Dakota and Montana in the US and Manitoba and Saskatchewan in Canada (Fig. 1). An unconventional reservoir, the Bakken formation is one of the last giants to be discovered in North America. The US Geological Service estimates that the undiscovered US portion of the Bakken formation holds 3.65 billion bbl of oil, 1.85 Tcf of associated gas, and 148 million bbl of natural-gas liquids.

Advances in horizontal drilling of extended-reach wells and in completion techniques have increased the amount of recoverable oil and gas. Wells drilled in the Bakken are typically drilled horizontally across two 640-acre sections, with laterals that can extend more than 9,000 ft. Two completion methods known for cost-effectiveness and high well efficiency that are used in these wells are the openhole-packer system and the sleeve one-trip system.

Openhole-Packer and Sleeve Completions

Openhole completions performed in the Bakken are commonly run as a one-trip system on drillpipe containing the following equipment: a hydraulic or mechanical running tool, liner-top packer or liner-hanger system, openhole packers, fracture sleeves, and float equipment. Once the system is in position, the appropriate fluid is displaced, and the liner-top-packer is set; the running tool is dis-connected from the system and removed from the well. The openhole packers pro-vide compartmental isolation along the horizontal wellbore with fracture sleeves placed at each stage, forming a pathway for stimulation fluid and the production of hydrocarbons.
Real-Time Analysis for Remote Operations Centers
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16999, ’Remote Real-Time Analysis - A Game Changer for Remote Operations Centers,’ by Erland Saeverhagen, Arve Thorsen, Jan Ove Dagestad, Nic Spanovic, and Kate Cannon, SPE, Baker Hughes, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.

Drilling completion, production, and general surveillance are all areas that benefit greatly from remote real-time analysis. However, several challenges to remote services exist, including communications issues, fear of job loss, and working outside one’s comfort zone. What is considered an important development goal for a business might be regarded as a threat to an individual, leading to reduced development within remote services.

Remote-Operations Business Model

A remote-operations business model removes geographic location and physical distance in all phases of oilfield-service delivery. It reduces the cost of delivering services, increases geographic reach, and improves safety. Remote operations, in essence, are real-time workflows that integrate personnel at rigsites and at assembly and maintenance and overhaul (AMO) facilities; at remote operations centers; or at real-time operational centers (RTOCs) anywhere in the world.

Remote operations are the acquisition of sensor data from rigsite equipment and instruments, and the transmission and processing of those data from remote locations. Monitoring, alarm, or advisory services are delivered in real time with global delivery models, increasing the capability to move work from the point of service to another lo cation, where it can be performed more safely, more quickly, and at a lower cost.

Infrastructure, while critical, is only an enabler. The true sources of efficiency and competitive advantage come from the organizational redeployment of the workforce and the re-engineering of workflows. Providing on-demand expertise enables service providers to deploy new technology faster and deliver high-end services in areas with few local qualified resources. Customers also benefit from bundled services, which require the integration of different disciplines and expertise that may be in short supply.

The Digital Oil Field

Improved connectivity through radio link, fiber optics, and satellite systems has opened a new world of opportunities for operation optimization. Real-time operations monitoring occurs from any office, accessing data streams through Web portals. New downhole tools and software have been developed on the basis of these new abilities, and new service levels have resulted, leading to new and interesting jobs, improved well placement, high service quality, and reduced non-productive time (NPT).
En Route: CO2 Stories
Authors: Labastie Alain
Published: February 2015

President's column

The second SPE International Conference on CO2 Capture, Storage, and Utilization will be held 10-12 November in New Orleans. CO2 issues are at the center of many controversies, within the general public as well as the scientific community and even the oil and gas community. These controversies may have a significant impact in our industry, so I would like to take this opportunity to share with you some personal thoughts on the subject.

It is important to make a clear distinction between facts, which are well established, and theories or interpretations, which may be subject to intense discussion. Let's start with facts.

CO2 concentration in the Earth atmosphere has been increasing since beginning of the industrial era, about 150 years ago. This increase is well correlated with the intensive use of fossil fuels as energy source.

There are many substances acting as greenhouse gases (GHG) in the atmosphere, the most important being water vapour. However, only the concentration of CO2 has significantly increased in the past century.

The oil and gas sector accounts for one-third of GHG emissions, but this is mostly due to the end users, you and me: transportation, heating of buildings, etc. The oil and gas industry itself, including E&P, refining, and distribution of petroleum-related products, accounts for only 5% of the global GHG emissions, much less than agriculture (share=14%) or deforestation (share=17%).*

This is important to remember: our industry is perceived as being responsible for a large fraction of GHG emissions, and this is not true. The end users-i.e., the general public-are responsible, and they don't realize that.

However, many unconventional hydrocarbons that we are beginning to produce have much higher CO2 emissions per barrel, as compared to conventional light oil. For example, emissions from extra-heavy oil produced by thermal methods are 4 times higher, and even 10 times higher if we include upgrading. (This is due to steam generation and heating for upgrading.) Another example is synthetic fuels from gas-to-liquids (GTL) conversion (Fischer Tropsch process), which are 15 times higher in CO2 emissions than conventional oil.

These are facts, well established. Let's talk now about interpretations and theories. One of the most controversial is the concept of global warming, which is creating a lot of . . . 'warm' discussions. This is only a theory; apparently the data are not sufficient to establish that as a fact (I am not a climate scientist, so I don't want to elaborate on that).

However, it is fact that there are hundreds of peer-reviewed scientific papers confirming the global warning concept, and not a single one, to my knowledge, stating the opposite. Again, I am talking only about peer-reviewed papers, which are supposed to give sound information.
Sand-Control Reliability: Finding the Sweet Spot
Authors: Green Annabel
Published: February 2015

Guest editorial

Sand control represents a diverse range of technologies designed to meet the demands of hydrocarbon recovery from weak sandstone formations. Although the technology is developing and improving, industry adoption of new sand-control techniques is typically much slower than for oilfield technologies in general.

While is it often necessary to control the unwanted production of reservoir sand into the wellbore, sand-control techniques to varying degrees add cost and complexity, yet are operationally unforgiving and have relatively poor long-term reliability. Added to that is a single-point critical failure mode in a completion that is often both unrecoverable and unrepairable. The challenge, then, is to provide sand-control technology that addresses these weaknesses and to select solutions that will maximize value for any given application.

This fundamental challenge is unchanged from the time when sand control was first installed in wells more than 100 years ago; what has changed is the variety and complexity of applications. For example, extended reach, high rate, deep water, high-pressure/high-temperature, heavy oil, multilateral well construction, and reservoir segmentation all place differing demands on the sand-control completion but all represent higher-cost environments in which maximizing the return on investment is essential. In response to this increasing diversity and criticality, the industry has seen an increasing range of sand-control techniques. There are now at least 20, many of which are “new,” have evolved, or are under development. But since none is a panacea, how do we evaluate and rank this increasing range of options and application challenges to maximize net present value (NPV)?

There are three key factors in determining NPV: cost, performance, and reliability. The cost element is relatively simple. Operating expenditure, capital expenditure during installation, and the cost of failure—lost production and remediation—can be readily quantified. And generally, even for new techniques, the tools exist to model the well performance and confidently predict (at least) relative performance. While the performance of sand-control completions for some solutions is determined by the productivity reduction that occurs due to skin damage or wellbore size reduction, performance can also be positively influenced. Sand control with stimulation techniques or chemical treatments can increase productivity, and inflow-control technology can be combined to aid wellbore cleanup and improve ultimate hydrocarbon recovery. More recently, options for additional functionality have been introduced to provide degrees of reservoir management.

Having quantified cost and performance, what is left is reliability, and herein lies the challenge that is in many ways unique to sand control.
Platelet-Technology Applications Provide Economic Remedy for Well-Integrity Problems
Authors: Stewart Kevin
Published: February 2015

Technology Update

Up to 40% of the world’s oil wells are shut in, or operating with dispensation, because of well-integrity problems. With the proportion that large, these wells collectively represent major potential for increasing production to meet oil demand—growing globally each year by 1 million BOPD—if improved and more-economic remedies for these problems can be found. Better remedies can reduce the need to drill new wells.

With the right technology, leaks in casing, tubing, well valves, and connections can be diagnosed relatively easily. However, fixing them has traditionally been more difficult. Issues typically have included cost, availability of rigs or workover units, personnel requirements, leak-fixing processes, weather, and third-party dependencies. These various considerations can result in extended and long lead times to bring shut-in wells back on line or indefinite postponement of needed interventions on wells that are operating.

There are also significant planning and logistics issues, and lengthy down-time can result. Well output could be partially or totally lost for months—affecting production quotas and revenue targets—before a rig is mobilized and deployed. And rig workovers can be complex and risky. Removing a well-head during a workover, for example, could affect well integrity and bring about health, safety, and environment (HSE) risks bigger than the problems the workover is intended to remedy.

Brinker Technology has recently developed a system called Platelets, a rigless, through-wellhead workover technology that allows the major planning, logistical, and downtime issues of traditional work-overs to be avoided and commensurate cost savings to be achieved.

In concept, the technology functions similarly to the way the human body responds to cuts and wounds, where platelets in the blood are drawn to the cut and create a seal. The oil and gas technology is designed around free-floating, discrete particles conveyed by means of an inert carrier fluid. The platelets deployed in this technology are specifically engineered for the size of the leak and the operating conditions of the system. Platelets are pumped down-stream while suspended in the carrier fluid and, when they reach a leak, pressure-differential forces entrain them into the defect to create a mechanical seal (Fig. 1). The polymeric and elastomeric materials incorporated in the platelet technology produce a seal more durable than steel and have no negative effects on the treated infrastructure.

The platelet technology previously has been applied in subsea pipelines and water-injection systems. Its applications have now been extended to casing, tubing, well valves, and connections. The technology includes specific designs for both static- and dynamic-sealing applications. Additionally, by incorporating specially designed software, the technology can be used diagnostically to locate leaks (Fig. 2).
Subsea Developments Key To Future Production
Authors: Thomas Mark
Published: February 2015

Ongoing advances in subsea technologies and their proven application in offshore regions around the world mean that there can be few, if any, other areas of the upstream industry that can claim such strong prospects for the future. With exploration and development projects routinely taking place in waters well beyond 1500 m, and with some nearing the 3000 m mark, the need for reliable subsea systems and hardware—and continued essential R&D—remains paramount if oil and gas companies are to access the new and increasingly remote reservoirs they need to replenish their own reserves and meet the demands of an ever-thirsty global energy market.

The future of the subsea market looks remarkably promising. The case looks even more solid when you consider that many observers appear to forget that subsea does not just mean deep water and harsh environments—there are dozens of developments currently under way or in the pipeline in much less than 400 m of water that will require subsea systems and hardware. When you consider that whatever the basic offshore design or concept—drilling rig, fixed production platform, floating production facility, or total seabed-to-shore package—subsea equipment of one form or another is required, the view gets even better.

Add to this the increasingly cost-effective subsea systems also being introduced to the market or further refined, with various seabed processing, separation, boosting, and compression designs either in action or emerging for pioneering projects around the world within the next year or two, and the fundamentals become even more reassuring, not only for the industry itself but also for shareholders and an investment community looking for lower-risk options post-Macondo.

 Some of the offshore industry’s leading authorities are forecasting that, despite some relatively short-term delays in the US Gulf of Mexico, the future for the subsea market is healthy up to 2014 and beyond. Infield Systems says in its latest market update that the subsea sector’s future looks good due to the basic factors of reserve depletion in shallow-water regions, increased deepwater activity, and enhanced-oil-recovery efforts and techniques. “More than USD 87 billion will be invested in development drilling and the manufacturing and hooking-up of subsea units to 2014. This represents a substantial 30% increase over the previous 5 years,” it states.
An Ultradeepwater Heavy-Oil Development Offshore Brazil
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 20537, ’Parque das Conchas BC-10 - An Ultra- Deepwater Heavy Oil Development Offshore Brazil,’ by K.H. Stingl, Shell International E&P, and A. Paardekam, SPE Shell Brazil E&P, originally prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed.

Parque das Conchas is an ultradeep-water heavy-oil development in the northern Campos basin offshore Brazil. The project is a joint venture between Shell, Petrobras, and Oil and Natural Gas Corporation of India. The first phase of the project is the development of three independent subsea fields tied back to the centrally located turret-moored floating production, storage, and offloading (FPSO) host facility, the FPSO Espirito Santo.

Introduction

The Parque das Conchas development grew out of a substantial exploration and appraisal program beginning in 2000 in which 13 wells were drilled and six discoveries were made. The Declaration of Commerciality was signed with the Brazilian National Petroleum Agency in December 2005, and the project was sanctioned in November 2006. The four main reservoirs—Ostra, Abalone, Argonauta B west, and Argonauta O north—were named after shellfish indigenous to the area. Together, they form “Parque das Conchas,” or “Shell Park,” in Portuguese. This is the first project in Brazil taken by Shell from exploration discovery to production. First oil from Phase 1 was achieved on 12 July 2009, just 9 years after discovery.

Development

Abalone, Ostra, and Argonauta B west are small-to-medium in size and stratigraphically complex, with highly faulted, compartmentalized, unconsolidated sand packages. The reservoir pressures are low, and the oils range from heavy to light, ranging in gravity from 17 to 42°API. A fourth heavy-oil field, Argonauta O north, will be tied back as part of Phase 2 and is planned to be ready for production in 2013. The Argonauta O north field contains 16°API oil and will require waterflood for reservoir-pressure support.

The Phase 1 subsea infrastructure consists of 10 producing wells and one gas-injection well connected by 100 km of insulated and uninsulated flowlines ranging in size from 6 to 12 in., 15 flow-line sleds, two production manifolds, two artificial-lift manifolds housing a total of six vertical subsea-separation caissons with 1,500-hp electrical submersible pumps (ESPs), and 25 rigid jumpers, all of which are serviced by approximately 30 km of multicircuit high-voltage electrohydraulic (HVEH) umbilicals connected to the FPSO.

The gas is processed on the FPSO, and to avoid flaring and to reduce CO2 emissions, it currently is being injected into a gas-injection well. A dedicated 40-km-long 6-in. uninsulated Parque das Conchas trunkline has been installed from the FPSO and will be tied into the Petrobras Caipixaba gas-export pipeline at the Petrobras BC-60 location scheduled to be operational in 2010. The oil is stored on the FPSO and offloaded to shuttle tankers as required.