This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 184648, “Integrating Human Factors Into Well Control,” by Jacob Odgaard, SPE, and Tim Morton, SPE, Maersk Drilling, prepared for the 2017 SPE/IADC Drilling Conference and Exhibition, The Hague, 14–16 March. The paper has not been peer reviewed.
Many of the worst oilfield incidents have been attributable to human factors. Consequently, a corporate well-control manual was refreshed to include human factors in the management of well-control incidents. This required mapping the well-control process, assigning specific roles to personnel, and defining contingencies while acknowledging the effect human factors have on the personnel involved. The intention was not to create a rigid structure but rather to provide a framework to guide the front line in dealing with a well-control event.
The corporate well-control manual was updated to introduce human factors and consolidate a number of improvements. Numerous references were consulted, including other industry well-control documents, trade publications, and academic papers.
“Human factors” refers to technological, organizational, and job factors, as well as human and individual characteristics that affect how people perform a job. It includes the competence and behavior of personnel, the design and functionality of equipment, and organizational structure and support.
Why was it necessary to include human factors in something as fundamental as a well-control manual? Many diverse challenges are faced in well control, often involving multiple complex interfaces in a high-stress environment. Frequently, the problem is not fully understood, either. The challenges of decision making in such a pressured environment have been recognized in other industries, and they share many similar features.
The recognition in the drilling industry to include human-factors mitigation into emergency management and, specifically, well control was one of the outcomes of the Macondo disaster. Recognizing the importance of this, a Human Factors Task Force was established to identify improvements related to human factors and their contribution to such incidents. Training- and competence-assurance guidelines were issued, and objectives were set to provide a step change.
Human Factors in Well Control
Well control is often a stressful, high-risk situation, and it is important to understand the effect of how people perceive and react to a well-control situation.
Mental Traps. Managing a well-control situation is stressful, and a number of mental traps need to be dealt with for a successful outcome. These traps are common in situations similar to well-control incidents, and they increase under time pressure or when people become fatigued because of long periods of stress, both of which are experienced frequently in a well-control incident.
Cognitive Biases. A cognitive bias typically occurs when information is interpreted and an attempt is made to simplify complex information.
A cognitive bias may also be seen as a tendency to confirm some preconception or possibly discredit some information that does not support an entrenched view. Such biases have a major influence on the ability of both the individual and the team to understand what is happening during a well-control operation.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 181680, “A Continued Assessment of the Risk of Migration of Hydrocarbons or Fracturing Fluids Into Freshwater Aquifers in the Piceance, Raton, and San Juan Basins of Colorado,” by C.H. Stone, SPE, A.W. Eustes, SPE, and W.W. Fleckenstein, SPE, Colorado School of Mines, prepared for the 2016 SPE Annual Technical Conference and Exhibition, Dubai, 26–28 September. The paper has not been peer reviewed.
Wellbore-construction methods, especially casing-and-cementing practices for the protection of freshwater aquifers, have been reviewed in the Piceance, Raton, and San Juan Basins in Colorado. The assessment confirms that natural-gas migration occurs infrequently but can happen from poorly constructed wellbores. Analysis confirmed no occurrence of hydraulic-fracturing-fluid contamination. The significance of these results is to help quantify the risks associated with natural-gas development as related to the contamination of surface aquifers.
The prevention of contamination of freshwater aquifers has been a prime concern in drilling operations since the inception of drilling. Surface casing has long been the primary barrier to prevent contamination of freshwater aquifers through wellbores. The probability of leakage into aquifers from wellbores during shale development has a wide range of estimates, complicated by the presence of hydrocarbons at shallow depths in many parts of the world. An earlier paper reviewed the process and outcomes of a study for the Wattenberg Field in the Denver-Julesberg Basin. This study continues the examination of the contamination of aquifers in the subsurface during the completion and the production phases of the well and quantifies the risk of contamination of aquifers through failure of the wellbore for three other major basins in Colorado, the Piceance, Raton, and San Juan Basins. This synopsis focuses on the assessment of the Piceance Basin.
Barrier Definition. Common vertical, deviated, and horizontal subsurface wellbore-barrier designs were grouped and ranked on the basis of the risk of multiple barrier failures (Fig. 1). For the sake of clarity, pressure monitoring of the casing annulus [surface annulus pressure (SAP)] was not assumed to be an additional barrier during the production phase even though it is frequent and often required by state regulations.
Well-barrier designs can vary from field to field depending on geology, trajectory, depths, anticipated pressures, expected hydraulic-treatment rates, and estimated production rates. Whether a well is horizontal, vertical, or deviated has no significance with respect to the ultimate protection of freshwater aquifers because the wells are designed to protect the shallow vertical section of each oil and gas well. Multiple barriers must be in place near the depth of the freshwater aquifer to prevent breaching of a single barrier potentially leading to contamination.
Africa was first called the “Dark Continent” in the 19th century. The term is originally credited to the famous explorer Henry Stanley from his 1878 book “Through the Dark Continent.” Back then, Africa was a mysterious and dangerous place for European explorers.
Today, when I conclude most of my presentations, I use the NASA satellite photograph of the world at night. In it, Africa is mostly dark, so from an energy standpoint, it’s still a “dark continent.” According to the World Energy Outlook 2017, two-thirds of people in sub-Saharan Africa do not have access to electricity. More than half of the population uses wood and charcoal as its primary energy sources, and that is expected to continue until 2040. Lack of access to energy holds back the promise of Africa and its people.
I have spent a lot of time in Africa in the past 10 years. Not only have I traveled to Angola through my position with Chevron, but I also have vacationed there. Most recently, I have traveled to Angola as SPE President. Africa is, in many ways, the final frontier. There are many exciting new developments in African exploration and production that hold tremendous potential to bring more energy and prosperity to the continent—and shine a light of affordable, abundant energy.
West Africa has dominated the continent’s production for more than 50 years since Shell/BP began production in the Oloibiri field in the Niger Delta in 1958. Similarly, Gulf Oil—now Chevron—began offshore production in the Cabinda province of the Congo River basin in Angola in 1968. Angola had a long history of oil seeps dating to 1700s. The first onshore production was in the Benfica field in 1956, but the Malongo field was the first significant commercial production.
Despite long enjoying control over African production, both Nigeria and Angola are now struggling to find the right split between government and commercial interests for in-vestment to continue. Estimates are that investment in deep-water Angola and Nigeria has been cut by USD 100 billion. Without new investment, production will decline by half of its current level.
Nigeria is restructuring its governance and petroleum industry financing, which—if successful—should bring stability and greater investment back into the Niger Delta. Offshore Angola projects are suspended across all operators, pending fiscal reforms that reduce government share under current production-sharing contracts, which can be as high as 90%.
Subsea separation and produced water reinjection (PWRI) or discharge comprise an integral part of the subsea processing strategy that can bring many benefits, including economic, operation-al, and environmental, for the oil and gas industry. The importance of subsea separation and PWRI to economics has been demonstrated through work done by Statoil, which installed the world’s first full-scale subsea separation system at its Tordis field in the North Sea.
Statoil estimated that the system’s installation would enable the company to achieve an additional total field oil recovery of 6%, which is equivalent to an extra 26 million bbl of oil. At a price of USD 50/bbl, this would lead to more than USD 1 billion of extra revenue.
The most economic means of implementing subsea separation and PWRI or discharge operations is to use continuous online subsea water-quality measurement devices.
The alternative of using a remotely operated vehicle (ROV) to extract and deliver produced water samples to the surface for offline analysis has been estimated by the Research Partnership to Secure Energy for America (RPSEA) to cost as much as USD 250,000 per day. It is also time consuming, and the processing conditions could change before the results are obtained.
However, few subsea online continuous monitoring devices exist for measuring produced water quality. But there are moves within the industry to address this problem, given the enabling status that the technology holds for deepwater/ultradeepwater and marginal field development.
A number of joint industry projects (JIPs) and other initiatives have been launched globally and have made progress in developing technical specifications, identifying possible technologies, and assessing the performance of potential sensors under laboratory and field (at surface) conditions.
The most obvious consideration is that subsea separation and PWRI or discharge require online monitors to operate reliably and accurately at a water depth of up to 9,850 ft, which brings the additional challenge of operation at high temperatures and pressures.
Depending upon the type of operations, there are also differences in the technical requirements. For subsea discharges, the focus will be on the measurement of oil-in-water, while for reinjection, the emphasis will be on the measurement of solids and oil for concentration and particle size.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 27661, “How Will Subsea Processing and Pumping Technologies Enable Future Deepwater-Field Developments?,” by Phaneendra B. Kondapi, Texas A&M University, and Y. Doreen Chin, Ashesh Srivastava, and Zuying F. Yang, Subsea Engineering Technologies, prepared for the 2017 Offshore Technology Conference, Houston, 1–4 May. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission.
This study examines how subsea processing (SSP) can develop into an important enabling technology for future ultradeepwater-field developments and long-distance tiebacks. The authors identify the gaps that need to be closed and describe the decision-making process during the field-development life cycle by considering the technical and economic constraints of various SSP technologies.
A generalized definition of SSP is any active treatment of the produced fluids at or below the seabed to improve recovery factor of reservoirs. SSP technologies include multiphase pumping, subsea separation, gas compression, and raw-seawater injection.
Subsea separation coupled with liquid boosting is effective in enabling production at very low flowing tubinghead pressures, even in deep water. This method also is well-suited for use where heavy, viscous oil or low reservoir pressure is the rule. Gas fields often are developed with subsea wells and multiphase transport to onshore facilities or to offshore processing platforms. Separation allows decreasing boosting-power requirements. Subsea-separation technology is progressing quickly because of its huge potential in minimizing topside water-handling requirements and separation of gas, oil, and water from the production fluid. Subsea gas-compression technology is one of the faster-growing technologies for large fields requiring pressure boosting (e.g., where subsea-to-beach development solutions result in long tie-back distances). It improves the production and recovery from the reservoir by reducing backpressure on the wells.
As of this writing, more than 25 subsea boosting systems and six major subsea separation systems have been installed or awarded throughout the world. Given the growing number of greenfield and brownfield applications, some analysts anticipate the number of SSP systems installed globally to double by 2020.
The complete paper contains a detailed discussion of the development of these technologies, from their origins to their current incarnations.
SSP is typically considered for systems with a tieback to a host structure and can influence all phases of project life (start-up, plateau production, late life, and tail end). SSP can consist of the following:
BP is working to push digital rock testing into the mainstream of conventional development.
The latest step in its decade-long journey was a deal with Exa, a software firm that partnered with BP to develop a program modeling two-phase flow in conventional reservoirs based on data from virtual 3D images of small samples of reservoir rock.
Compared with methods used by traditional core labs, this approach significantly reduces the time and cost required, and offers the processing software in a form that could help broaden the use of this disruptive technology.
These tools and methods will be used by BP’s technology center to generate reservoir rock property data that will be used by BP’s asset managers to consider how to better manage a wide range of conventional reservoirs, said Joanne Fredrich, upstream technology senior advisor at BP.
The system measures relative permeability—in this case the degree that flow rates are reduced when oil and water are mixed—using a 3D digital image based on scans of small rock samples by a micro CT, known in the medical field as computed tomography. CT machines are used for medical scanning and are able to image extremely fine details.
Relative permeability has been notably lacking from BP’s long list of conventional reservoir tests using digital rock analysis, which range from measures of reservoir porosity to electrical resistance. Absolute permeability has been available, but that measure of single-phase flow is not a good representation of reservoir reality.
“We have so little relative permeability data. We see this as a potential game changer for subsurface modeling that more accurately characterizes reservoirs,” Fredrich said.
Measures of relative permeability have long been done in core labs. Digital analysis can reduce the time required to get back relative permeability results from a year or more to a couple of weeks or less, and the software can be scaled up to allow BP to speed work by running simulations on thousands of processors at its supercomputing center, she said.
The software deal with Exa allows BP to use the software it helped develop with the maker of fluid flow simulations, and for Exa to market it to other users.
“We are the first company to bring an accepted, credible technology to market” to simulate multiphase flow and predict relative permeability using this sort of data, said David Freed, vice president of oil and gas for Exa.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 185226, “Integrated Approach in Fatigue Management,” by M. Nizam Jemoin and Ahmad Khairi Abdullah, Petronas, prepared for the 2017 SPE Asia Pacific Health, Safety, Security, Environment, and Social Responsibility Conference, Kuala Lumpur, 4–6 April. The paper has not been peer reviewed.
In an effort to establish practical solutions to fatigue-related risk, Petronas created a task force that included specialists, plant-operation personnel, shift supervisors, and information-technology (IT) team members. Discussions with stakeholders included a detailed review of the shift-manning procedure and work-process evaluation to address fatigue risks, and an analysis was performed to determine common issues that require further mitigation efforts. This paper describes the integrated approach taken by the company to reinforce effective management of fatigue.
Investigations into some of the worst industrial and environmental accidents have identified fatigue as a major contributor, although, in some of these cases, fatigue was not the only cause. Petronas has put in place a number of key controls to ensure that fatigue risks are managed accordingly at the workplace. These include a technical standard on management of fatigue, site procedures at operating units (e.g, shift-manning procedures, journey-management plans, and health-promotion programs), and audits to ensure compliance. Nonetheless, opportunities exist for improvement, particularly to reinforce the effective implementation of the program through integrated approaches that leverage IT and standardized work processes. Embedding fatigue management in day-to-day work processes is essential to achieve significant results in managing the risks.
Statement of Theory and Definitions
Fatigue is a progressive decline in alertness and performance caused by insufficient quality or quantity of sleep. This may result from extended work hours, overtime, shift work, insufficient opportunities for sleep, or the effects of sleep disorders or medical conditions that reduce sleep or increase sleepiness. Fatigue affects the ability to assess risk, increases willingness to accept risk, and decreases the ability to maintain attention. When fatigued, people find it more difficult to divide their attention adequately between multiple tasks and to plan for future actions. Fatigued people are more likely to suffer lapses in concentration and are more easily distracted from the task at hand. The more tired people become, the more likely they are to cut corners and to accept lower standards in accuracy and performance.
Fatigue contributes to accidents by impairing performance and, at the extreme end of the scale, by causing people to fall asleep while working. Human error resulting from fatigue is now widely acknowledged as the cause of numerous workplace disasters. Many disasters began with initial difficulties such as technical faults, but, because of fatigue, the operators did not manage the situation adequately, allowing the situation to escalate to an accident.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 27639, “Significant Cost Reduction of Subsea Boosting Systems by Innovative Technologies,” by J. Davalath and D. Wiles, TechnipFMC, prepared for the 2017 Offshore Technology Conference, Houston, 1–4 May. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission.
One of the more promising opportunities for brownfield investment is low-cost subsea boosting systems. These projects do not require the drilling of new wells or significant infrastructure investments in new subsea equipment or new topside facilities. Incremental investments in low-cost boosting systems result in substantial increases in revenues and, therefore, high rates of return. The costs of subsea boosting systems have been reduced by adopting three primary strategies: simplifying the system design to reduce weight and cost, simplifying the installation and intervention, and reducing complexity and risk.
Analyses of well and reservoir conditions suggest that there are hundreds of wells worldwide that have the economic potential for low-cost subsea boosting. The return on investment (ROI) in these cases ranges from 250% to greater than 500%. Subsea boosting systems are a robust and mature technology; worldwide, more than 65 mudline units and more than 50 submersible pumps have been installed. Consequently, 19 operators have addressed production challenges with subsea boosting technology.
Key applications have used subsea pumps as part of a subsea-processing station. For example, subsea pumps were installed to boost liquids separated subsea in three-phase separation systems, for the purposes of debottlenecking topside facilities, in the Petrobras Marlim project and the Statoil Tordis project, the former with horizontal pipe separator technology and the latter with conventional horizontal three-phase separator technology.
Subsea pumps have also been installed downstream of gas/liquid separators in Angola’s Block 17 in the Pazflor Field. This application enabled a higher-pressure boost than could be achieved by multiphase pumps available at that time. The separation of the gas from the liquid enabled the use of a hybrid pump, with centrifugal stages in addition to the helicoaxial stages typical of a multiphase pump, to provide a higher differential pressure.
Improvements in multiphase-pump technology have occurred such that higher differential pressures can be generated as a result of high-speed-motor technology, rapid-control technology, and monitoring systems. Therefore, subsea boosting stations have become less-expensive and more-reliable solutions for increased oil recovery (IOR).
Market PotentialThe need to reduce the backpressure on producing wellheads, and increase the recovery factor from oil and gas reservoirs, is omnipresent in subsea fields. The decision to install subsea boosting on the mudline is made in the context of the incremental improvement in recovery achievable with a subsea pump vs. the recovery achievable by producing the field naturally or by other IOR technologies. Operators have studied key oil-producing regions and have identified many instances in which mudline boosting is the most-viable alternative.
Not too long ago, horizontal drilling revolutionized the petroleum industry. Emerging logging-while-drilling and geosteering technologies helped bring about multilateral, maximum-contact, and smart-completion wells, allowing reservoirs to be developed and produced much more efficiently and economically. This increased recovery, thus boosting reserves. In the process, formation evaluation plays a critical role in determining whether a producer or an injector is successful.
More recently, efficient mass horizontal drilling and optimized multistage massive fracturing have turned traditionally nonreservoir source rock into sweet spots of energy strategy on a global scale. Production from unconventional reservoirs in the last decade has dramatically changed the petroleum industry, and this movement continues to evolve. Developing unconventional resources demands unconventional thinking, mainly because of the many challenges involved in evaluating tight source rocks. The two fundamental petrophysical properties, pore structure and wettability, are completely different between conventional reservoirs and unconventional source rocks.
What may be next on the horizon?
It is estimated that methane hydrates contain much more gas than shale plays, and, understandably, many countries are keen to explore this vast potential. As per recent news releases, China Geological Survey geoscientists and China National Petroleum Corporation engineers may have made a great technology breakthrough by being able to test significant hydrate-gas production in the South China Sea. If this is sustainable, exploring hydrate gas may be the next game changer for the energy industry. Evaluating hydrate gas formations would not be easy, however, and producing them safely, economically, and in an environmentally friendly way would be very challenging. But, I have high hopes that future technologies will be able to resolve these challenges to produce hydrate gas conventionally so it can be used to improve living standards.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 182448 The Petrophysics Role of Low-Resistivity Pay Zone of Talang Akar Formation, South Sumatera Basin, Indonesia by Z. Holis, SKK Migas, et al.
SPE 183883 Using Digital Rock Modeling To Estimate Permeability and Capillary Pressure From NMR and Geochemical Logs by Hao Zhang, Baker Hughes, et al.
SPE 183800 An Innovative Approach for Integrated Characterization and Modeling of a Complex Carbonate Reservoir by F. Ben Amor, Schlumberger, et al.
Round Two in Mexico: 10 More Offshore Fields Awarded
Trent Jacobs, JPT Digital Editor
The first tender of the second round of Mexico’s oil and gas licensing auctions issued 10 awarded areas to more than a dozen different oil and gas companies. In addition to Mexico-headquartered companies, other winning firms hail from Russia, Malaysia, US, and the Netherlands.
Five locations received no bids, including some that were understood to be gas-rich and therefore a challenging investment due to the relatively low-cost gas imports coming from the US.
Growing Number of Projects Go Forward, but the Global Backlog is Still Building
Stephen Rassenfoss, JPT Emerging Technology Senior Editor
There are recent signs of life in the exploration sector, with as many delayed projects getting funding during the first half of 2017 as in all of 2016.
A report from consultancy Rystad Energy tempers that assertion by describing the jump in the number of delayed projects getting a final investment decision (FID) as “apparent positive momentum.”
On the upside, it reported 17 delayed international projects have received an FID since it started tracking the many delayed projects in 2015 in the wake of the oil price plunge. The development cost of those projects is expected to be USD 78 billion.
H2O Midstream-Encana Deal Highlights Water Management Role in US Shale
Joel Parshall, JPT Features Editor
H2O Midstream’s recent acquisition of produced-water infrastructure from Encana Oil & Gas (USA) in the Permian Basin highlights the growing importance of efficient water management in United States shale plays. The acquisition, announced on 14 June, was concurrent with the execution of an acreage-dedication-based midstream water services agreement, under which H2O Midstream will gather, dispose, and deliver for reuse produced water for a substantial portion of Encana’s acreage position in Howard County, Texas.
By terms of the acquisition, H2O Midstream will now own and operate Encana’s existing produced-water gathering system that consists of more than 100 miles of interconnected pipeline and five saltwater disposal wells with a total permitted disposal capacity of 80,000 BWPD.
First Oil From Kraken: Offshore Project To Increase UK Production by 15%
Trent Jacobs, JPT Digital Editor
UK-based EnQuest achieved the delivery of first production from the Kraken offshore oil field on Friday, 23 June. Average production from the heavy-oil project is expected to reach 20,000 B/D of oil by year’s end.
Located almost 80 miles to the east of the Shetland Islands, the Kraken field holds an estimated 128 million bbl of reserves, according to EnQuest. The independent explorer has so far drilled and completed 13 wells, seven producers and six injectors.
US Crude Oil and Petroleum Products Exports Doubled Over Past 6 Years
Pam Boschee, Senior Editor
Following the loosening in December 2015 of US restrictions on exporting domestically produced crude oil, the US exported an average of 520,000 B/D, reaching 1.1 million B/D in February— the highest monthly level on record.
Crude oil and petroleum product gross exports more than doubled over the past 6 years, increasing from 2.4 million B/D in 2010 to 5.2 million B/D in 2016, according to the US Energy Information Administration.