Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Summary Wellbore-temperature logs and associated field-history data from a high-pressure/high-temperature (HP/HT) condensate North Sea platform are presented that validate the accuracy of a transient model of the multiwell thermal interaction (MWTI). The model is an updated version of previous work by McSpadden and Coker (2010) that simulates transient thermal interaction or "cross heating" between closely spaced wells of a template. As discussed in the preceding work, the MWTI alters final wellbore temperatures as well as formation temperatures in the interwell zone and also farther out from the well template. The multiwell thermal model is shown to converge closely in very characteristic fashion to two different logged and measured temperature profiles at a vertical depth range of more than 3,000 ft. The empirical data, including field history, represent a unique opportunity to study and understand this important topic. Before this current work, the authors’ experience found the industry discussion of the MWTI or "cross heating" to be largely anecdotal. Model validation against field data is necessary to achieve a full understanding of the physical system and to provide confidence in the predictive capability. The modeling of wellbore and formation temperatures for closely spaced wells has not been widely examined in the industry literature, as observed by Bellarby (2009). The current work presents an improved methodology on the basis of standard-industry techniques. The method uses standard industry thermal/hydraulic modeling software for a single well and a fully transient finite-difference model for the formation in a loosely coupled, iterative analysis. The iteration scheme is achieved by the coupling of the standard analytical solution for the isolated single-well temperature scenario with the solution in the formation for the cross-heating scenario. The effect of the MWTI is important for closely spaced wells such as offshore platforms or subsea and Arctic developments. The multiwell disturbance on formation and wellbore temperatures may affect well design, facilities planning, and operations. For example, given nominal flowing wellhead temperatures (FWHTs) approaching 350°F for HP/HT platform developments, even small temperature increases may have a critical impact on the design and layout of surface receiving systems. Annular-pressure buildup (APB), wellhead movement, tubular-stress design, cement-slurry design, subsidence/compaction effects, and facilities health and safety issues can all be affected. If the MWTI is not taken into account, then load events such as APB, wellhead movement, and thermally induced stresses may be underestimated. Concurrent and batch-drilling operations, including cementation, will also be affected.
- North America > United States > Texas (0.46)
- Europe > United Kingdom > North Sea (0.34)
- Europe > Norway > North Sea (0.34)
- Information Technology > Modeling & Simulation (0.88)
- Information Technology > Data Science > Data Quality (0.40)
Summary Underbalanced operations (UBO) are carried out to bypass drilling challenges that could be difficult to resolve by use of conventional drilling techniques. Steady-state multiphase-flow models are used to construct underbalanced-drilling operational windows. These advanced software models are deterministically formulated. It is known that some of the model input parameters, such as the multiphase-flow parameters, friction factors, and reservoir productivity, are subject to uncertainties. Failures to capture these variabilities may introduce some error in the model prediction, resulting in poor well planning and implementation. The purpose of this work is to implement probabilistic modeling of underbalanced drilling by use of a simple steady-state two-phase model. Both predefined uncertain and fixed factors serve as inputs to a pre-existing deterministic model. By applying Monte Carlo simulations, the model predicts outputs that follow a statistical distribution. A sensitivity analysis is conducted to determine the input factor that is most responsible for the uncertainty in the predicted bottomhole pressure (BHP). The results demonstrate that uncertainty modeling can improve underbalanced-drilling design and operations. A more realistic operational window is obtained, ensuring that underbalanced condition is maintained throughout the target section. With a better understanding of uncertainties and the corresponding impacts, well planners can make better decisions regarding well design criteria and safe operational conditions, and avoid huge economic consequences.
- Europe > Norway (0.68)
- North America > United States > Texas (0.28)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
An Efficient Implicit-Pressure/Explicit-Saturation-Method-Based Shifting-Matrix Algorithm To Simulate Two-Phase, Immiscible Flow in Porous Media With Application to CO2 Sequestration in the Subsurface
Salama, Amgad (King Abdullah University of Science and Technology) | Sun, Shuyu (King Abdullah University of Science and Technology) | El-Amin, M.F.. F. (King Abdullah University of Science and Technology)
Summary The flow of two or more immiscible fluids in porous media is widespread, particularly in the oil industry. This includes secondary and tertiary oil recovery and carbon dioxide (CO2) sequestration. Accurate predictions of the development of these processes are important in estimating the benefits and consequences of the use of certain technologies. However, this accurate prediction depends—to a large extent—on two things. The first is related to our ability to correctly characterize the reservoir with all its complexities; the second depends on our ability to develop robust techniques that solve the governing equations efficiently and accurately. In this work, we introduce a new robust and efficient numerical technique for solving the conservation laws that govern the movement of two immiscible fluids in the subsurface. As an example, this work is applied to the problem of CO2 sequestration in deep saline aquifers; however, it can also be extended to incorporate more scenarios. The traditional solution algorithms to this problem are modeled after discretizing the governing laws on a generic cell and then proceed to the other cells within loops. Therefore, it is expected that calling and iterating these loops multiple times can take a significant amount of computer time. Furthermore, if this process is performed with programming languages that require repeated interpretation each time a loop is called, such as Matlab, Python, and others, much longer time is expected, particularly for larger systems. In this new algorithm, the solution is performed for all the nodes at once and not within loops. The solution methodology involves manipulating all the variables as column vectors. By use of shifting matrices, these vectors are shifted in such a way that subtracting relevant vectors produces the corresponding difference algorithm. It has been found that this technique significantly reduces the amount of central-processing-unit (CPU) time compared with a traditional technique implemented within the framework of Matlab.
- North America > Canada (1.00)
- Asia (1.00)
- Europe (0.93)
- North America > United States > Texas (0.68)
Summary As an operator, Total has experienced significant deepwater maintenance andrepair activities, including cut-out and replacement of a damaged section ofwater-injection line, replacement of a flexible riser, replacement of an anchorline and its pile, and repair of an umbilical termination head (UTH). There are few deepwater-pipeline operators with experience in pipelinerepairs that need to be carried out with significant preparation time forintervention tools, including engineering and testing of the tools. Deepwateroperations [including inspection, maintenance, and repair (IMR)] require acompletely different paradigm than conventional offshore operations, with needfor specialized competencies, contractors, and tools. The pipeline-repairactivities mastered in conventional offshore operations are becoming difficulttasks in deep water because they have to be performed remotely and the pipelinecharacteristics are quite different. Furthermore, there are many importantchallenges that still need to be overcome, such as repair of pipe-in-pipesystems, repair of production bundle, repair of flowline with hydrogen sulfidecontent, and repair of flowline connection, all of which challenge research anddevelopment to find proper tools and methodologies for deepwaterintervention. This paper describes the strategy developed and implemented ondeepwater-pipeline intervention, based on a deepwater operational experiencebuilt over a decade. It also presents experiences of dealing with integrityissues and how to move forward in existing operations while preparing forfuture developments. Once the proper technologies are acquired, apipeline-repair system should be established as part of anoperational-management philosophy. From the design stage, an operator involved in the development of deepwateroperations should give serious consideration to how condition monitoring of thepipeline and its appurtenances will be performed and to how pipeline sectionswill be repaired or replaced should there be any failure during production.Being well prepared to face unexpected failures in the deepwater-pipelinenetwork would allow the operator to maintain the level of integrity of thedeepwater-pipeline network, minimize production loss and shortfall, minimizeintervention costs, and maintain the operator's image with international mediaand the national oil company.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 157022, ’Implementing a Process-Safety Program,’ by Saiee B. Julaihi, Saifuddin Shah B. Sowkkatali, and Rabiatul Adwieah Bt Shukor, Petronas Carigali, prepared for the 2012 SPE/APPEA International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Perth, Australia, 11-13 September. The paper has not been peer reviewed. Between 2006 and 2009, Petronas Carigali embarked on a process-safety program driven by concerns over an increasing trend of process-related incidents. The program focused on defining explicit process-safety expectations and then putting in place the required processes to intensify implementation and mandatory compliance. Some 3–4 years into the program, tangible improvement can be felt across the organization. Introduction Petronas Carigali has an established Health, Safety, and Environment Management System (HSEMS), developed and implemented in line with the company’s Group Mandatory Control Framework and its associated Group Technical Standard. The HSE Management System Manual broadly defines the company’s expectations for the effective management of matters relating to health, safety, and the environment. Associated procedures and guidelines define the processes by which compliance to the HSEMS is achieved. Process-safety expectations were generally included with those of occupational safety. In retrospect, this approach was far from ideal in that the organizational safety focus would frequently tend to be on occupational safety, with major-hazard management left primarily to the initial facilities engineering design. Process-Safety Framework The process-safety program culminated in the development and issue of Petronas Technical Standards in eight key process-safety areas: Design integrity (DI) Mechanical integrity (MI) Management of change (MOC) Process-safety information (PSI) Process-hazard analysis (PHA) Preactivity safety review (PASR) Operating procedures (OPs) Proprietary- and licensed-technology assessment (PLTA) On the basis of these distinct process-safety areas, Petronas Carigali was to incorporate these process-safety expectations as part of a substantially revamped HSEMS. Furthermore—and this was not done initially—operational procedures and guidelines defining the processes by which compliance is to be demonstrated needed to be formalized, to lend support in ensuring sustained compliance with the newly developed process-safety expectations. During the initial 3-year period from 2006 to 2008, minimal progress was made in the implementation of process safety throughout Petronas Carigali. Audit findings alluded to ineffective and nonsustained implementation throughout the company; this was attributed to a lack of (a) process-safety leadership, (b) competent resources through underestimation of the work involved, and (c) clarity regarding the processes required to demonstrate compliance with the HSEMS expectations. Consequently, a companywide review was carried out that culminated in the relaunch of the Petronas Carigali process-safety program (branded then as the Process Safety Change Management Initiative) in early 2009.
- Government > Regional Government > Asia Government > Malaysia Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Deepwater Developments Today’s deepwater projects are not just larger and more expensive than in years past. They are the most technically demanding projects the oil and gas industry has endeavored to undertake since stepping out from the continental shelf, and will require more new technology than ever to successfully execute. The extreme environments of deepwater fields are driving the complexity of these megaprojects to new heights, with shorter deadlines to help offset production declines. Among the companies capable of carrying out these record-setting field development projects is installation and subsea construction firm, Technip. The price tags of these projects have “exploded,” Pilenko said, because offshore oil and gas reservoirs are getting harder to find. So too is the challenge of safely producing those hydrocarbons and bringing them to the surface. “Today, we know how to drill at 3000-m depths,” he said. “But we are just learning how to produce it with qualified production systems.” Pilenko explained that the industry is not just pushing the frontiers of technology, but also geography. Offshore Africa, oil companies are proving how subsea fields can be developed with little to no onshore support infrastructure. One of the latest examples is the Moho Nord field, offshore Congo, where Technip will deploy some of its pipelaying and construction vessel fleet to install the entire subsea production system for operator Total. In terms of the scope of work, the project will be the largest subsea development that Technip has ever been awarded. The company will put into use many of its key assets to make and install the components of the subsea field that include 142 miles (230 km) of rigid pipeline, 14 miles (23 km) of flexible flowlines, and 31 miles (50 km) of umbilicals to deliver chemicals and power to the more than 50 subsea structures to be installed. Deepwater Facilities Under Construction Already the uncontested leader in spar development, having delivered 14 of the world’s 17 in operation, Technip is building three new spars simultaneously, including the world’s largest. Spars are deepwater floating facilities that rely on a cylindrical single-column design to achieve optimal stability for drilling and production in an offshore environment. The Technip-engineered Aasta Hansteen spar will be the biggest platform of its kind built, a distinction driven by the harsh environment of the North Sea and the fact that it is engineered for gas processing and storage. The hull will be 640 ft (195 m) from top to bottom and 167 ft (51 m) in diameter. The spar’s topside facilities will have a processing capacity of 812 MMcf/D of natural gas and a storage capacity of 160,000 bbl of gas condensate. The first spar to be installed offshore Norway, the Aasta Hansteen spar will operate at a water depth of 4,250 ft (1300 m) and is under construction in South Korea, with first production planned for the end of 2016.
- North America > Mexico (1.00)
- North America > United States (0.96)
- Europe > United Kingdom > North Sea (0.25)
- (3 more...)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > Mexico Government (0.48)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Walker Ridge > Block 508 > Stones Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Mississippi Canyon > Block 252 > Macondo Field > Macondo 252 Well (0.99)
- Africa > Republic of the Congo > South Atlantic Ocean > Lower Congo Basin > Moho Nord Block > Moho Field (0.98)
Guest editorial Control rooms have come a long way over the years, and there remains ample room for improvement. Fortunately for operators, though, a significantly improved control room of the future might be closer to reality than they think. Years ago, control rooms were dominated by large mimic panels covered with gauges and dials that provided a limited view and inflexible means of interacting with the process. Today, the modern control room includes sophisticated graphical user interfaces, and specialized furniture in purpose-designed spaces that make careful use of lighting and ventilation. The layout of the control room is arranged to accommodate the movement of people and to abate excessive noise. A control room may have a range of adjoining facilities, such as a kitchen and even gymnasium equipment, to help operators keep healthy and alert. Of course, not all control rooms are like this, but a state-of-the-art control room can provide operators with an environment that is, at least superficially, a pleasant and comfortable place to work. Although these advances have certainly improved conditions, several important areas could be further improved. Today’s operator console, a key element of the control room, is effectively an isolated island from which operators can rarely escape. Operators have difficulty moving away from the console to take brief breaks or work with others in the control room without losing critical situation awareness. Display layouts tend to be inflexible, often hamstrung by having to display information across multiple small screens, making it difficult for operators to access necessary information. The operator is also confronted with a multitude of devices such as keyboards, mice, radios, and telephones, and it is difficult for operators to work efficiently when constantly switching between devices. Additionally, consoles are difficult to scale from single to multiple operators and are typically engineered to cope with the maximum number of operators required for startup, shutdown, and turnaround operations. On top of this, the console’s physical arrangement does not allow operators working 12-hour shifts to get and stay comfortable. The result is that life for operators might be compared to traveling in economy class on a long, overnight, intercontinental flight while being asked to make rapid and critical decisions throughout the flight. The odds are stacked against the operators when they are uncomfortable and tired in environments that do not fully accommodate their basic physical and task-related needs.
S, which could cause sweet and sour corrosion. One of the costliest is corrosion. And if not selected and/or applied While fixed steel platforms are designed on the basis properly, coatings can degrade rapidly when exposed to that there will be external fouling (marine growth buildup), corrosive environments, such as seawater and the marine floating oil and gas facilities require routine maintenance and atmosphere. The quality of the coatings applied to a floating preventive solutions to control corrosion. The ramifications of water chemistries can initiate fouling and bacterial corroding offshore structures can take the form of added contamination, heavy-duty epoxies are used in the corrosion costs for new construction, maintenance costs on aging/ control design of structures and facilities, which are corroding equipment, inspections, structural integrity constructed mainly of carbon steel.
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Safety (1.00)
- (2 more...)
Young Technology Showcase Integrity management involves availability, access, and the analysis of necessary information. Even though you identify what is wrong, you need someone who is able to correct the issue and who has the correct spare part. Operators are focused on maintaining production and they prefer to conduct maintenance at planned intervals. When things start to fail, procedures exist for whom to call, how to troubleshoot, and what to do next. The goal of a condition and performance monitoring (CPM) system is to detect irregularities and the details associated with them before a production alarm situation is reached. That way, the appropriate action can be taken to ensure equipment availability (Fig. 1). The increase in field complexity and the decrease in the number of control room operators makes it necessary to think differently when it comes to integrity management. Integrated operations combine the operator and vendor in a common team for troubleshooting and solving issues. CPM is a solution developed by FMC Technologies to avoid unplanned production stops. How It Works Data collectors receive directly tagged information from subsea control systems. While the topside control system is primarily focused on production critical data, the CPM data collector also assesses equipment performance and internal housekeeping data from smart instrumentation and the control system itself. The data is also streamed to a location where the operator and the support organization can access it. The CPM software performs a combined analysis on the data stream and on historical data to present a picture of the current condition and performance of the field. All data is added to a historical database for later access. The graphical user interface is designed to help fault-finding and to enhance understanding of the condition of the equipment. The analysis process uses steady-state and dynamic models of the equipment performance to detect changes. Knowledge from the customer support organization and vendors is used to develop algorithms targeting relevant known failure modes and performance issues.
- Production and Well Operations (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems > Controls and umbilicals (0.52)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems > Subsea production equipment (0.52)
Natural Gas Seizing on historic margins in domestic prices, North American oil and gas companies are increasing their efforts to use more natural gas and less diesel fuel to power their field operations. Until now, oil and gas companies have been ordering natural gas-powered rigs to qualify the technology through pilot programs in the field. However, “the inflection point” may have been reached, said Brad Bodwell, senior vice president of corporate and business development at Prometheus Energy. The company is one of the largest suppliers of liquefied natural gas (LNG) to the North American oil and gas industry and is entering a stage of “rapid growth” because of economic forces and major gains in domes-tic gas production. As the technology is evolving, so is its nomenclature. Operators and service companies are using two terms to describe engines that are fueled by a simultaneous injection of natural gas and diesel: “dual fuel” and “bifuel.” Prometheus fueled up its first natural gas-powered generator sets on a drilling rig for operator EnCana in the Haynesville shale in mid-2010. “Since then, we have grown at a rate of about 80% per annum in terms of volume that we ship to our customers,” said Bodwell. In 2013, Prometheus had access to about 500,000 gal/D of LNG and was supplying seven operators in the United States and Canada. In total, North American LNG facilities produced 800,000 gal/D in 2013. New LNG facilities under construction and expansions of older facilities will bring the available supply of LNG up to 1.1 million gal/D by year-end. With several more plants already funded and expected to come online after 2014, the daily supply of LNG is projected to soar to 2.6 million gal/D after next year. Bodwell estimates that natural gas is fueling as much as 7% of North America’s 1,100 horizontal drill rig fleets, but he predicts that share to soar to 50% within the next 2 years. There are environmental drivers as well since natural gas is the cleanest burning of all fossil fuels (Table 1). “You’re getting a fuel that is going to reduce your environmental footprint and, at the same time, it saves enough money that it pays for the cost of conversion,” he said. “So we don’t need to wait to achieve some sort of scale benefit or a government injection of capital into the industry to make it work. It is all stuff we know how to do.”
- North America > United States > Texas (0.49)
- North America > United States > Louisiana (0.34)
- North America > United States > Arkansas (0.34)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Louisiana > Haynesville Shale Formation (0.99)
- North America > United States > Arkansas > Haynesville Shale Formation (0.99)
- North America > Canada > Alberta > Colorado Field > Bonavista Colorado 6-32-90-4 Well (0.97)