Pressure maintenance support in mature fields where permeability heterogeneity is present requires proper distribution of injected water into the respective zones of interest. This process can be extremely challenging, if no method for allocating the proper amount of water into each zone is available. An operator in the South China Sea, who had initiated a water injection project using legacy single-string two-zone completion technologies, found himself in this predicament, since no selective control for pressure maintenance had been considered for the project.
During the past few years, the application of intelligent completion (IC) technology has increased rapidly. This acceptance has been due primarily to its proven capabilities for reservoir monitoring and corresponding optimization of well performance without well interventions. Historically, the majority of IC applications have been in production wells; however, an increasing number of operators have started adopting IC technology for their injector wells.
This paper presents a case study in which IC technology was successfully applied in an offshore field in the South China Sea to provide an efficient water-injection method for optimizing pressure support as well as sweep. The operator selected this technology, as it presented a solution for optimizing the water injection. In addition to eliminating problems experienced with the incapability of the legacy completion technology to monitor water allocation and pressure maintenance for each zone, the IC technology would allow selective well testing for each zone. By evaluating the reservoir properties and characteristics of each zone independently, an intelligent completion would provide another key benefit to the operator, since it would comply with the platform size restrictions for the pumping equipment.
The paper will discuss field objectives, the conceptual design, the design obstacles, and the operational challenges experienced during the job execution.
The increase in offshore activity in harsh weather areas of the worldpresents a major challenge for those involved in the management and executionof lifting operations. This challenge becomes all the more important whenpersonnel are being transferred by crane. This paper examines some of the newtechnologies and operational philosophies that promise to help operators meetthese new challenges. This includes motion monitoring technology developed inNorway that provides accurate real-time data on vessel responses for mariners,and crane operators, allowing them to increase the safety and extend the limitsof lifting operations.
Crane operational downtime has a major financial impact on arctic projects.Therefore there is pressure to maintain continuity of lifting operations. Thisproven technology - the Deck Motion Monitor (DMM) and the Arctic personnelcarrier - allows the safe transfer of cargo and personnel for a higherpercentage of time and reduces the time spent waiting for an optimal weatherwindow.
The Schoonebeek heavy-oil field was first developed by Nederlandse Aardolie Maatschappij B.V. (NAM) in the late 1940s. Because of economics, it was abandoned in 1996. In 2008, the Schoonebeek Redevelopment Project, using a gravity-assistedsteamflood (GASF) design concept, was initiated with 73 wells (44 producers, 25 injectors, and 4 observation wells). Steam injection and cool-down cycles subject a cement sheath to some of the most severe load conditions in the industry. Wellbore thermal modeling predicted that surface and production sections would experience temperatures in excess of 285°C (545°F) and considerable stress across weak formations. A key design requirement was long-term integrity of the cement sheath over an expected 25- to 30-year field life span. Complicating this requirement was the need for lightweight cementing systems, because lost-circulation issues were expected in both hole sections, particularly in the mechanically weak Bentheim sandstone. The long-term integrity challenge was divided into chemical and mechanical elements. Prior research on high-temperature cement performance by the operator provided necessary guidance for this project. Laboratory mechanical and analytical tests were conducted to confirm the high-temperature stability of the chosen design. In addition to using lightweight components, foaming the slurry allowed the density, mechanical, and economic targets to be met. A standardized logistical plan was put in place to allow use of the same base blend for the entire well, adjusted as needed, using liquid additives, and applying the foaming process when necessary. This single-blend approach greatly simplified bulk-handling logistics, allowing use of dedicated bulk-handling equipment. The first well was constructed in January 2009; all 73 wells have been successfully cemented to surface. The steaming process, initiated in May 2011, has progressed with no well integrity issues to date.
In general, all of Shell's new field developments, and redevelopments of existing fields, are equipped with appropriate smart-fields solutions. The elements selected in each field depend on its features and conditions. A screening process is carried out in the early stages of the project to identify requirements and opportunities for implementation. In some cases, application has changed the development concept completely (e.g., field development with smart wells and a remotely controlled platform). In other cases, solutions help improve field management.
Tom Neville, SPE, and Adam Donald, SPE, Schlumberger A two-step analysis can provide the key information needed to design optimal shale completions. The first step is to evaluate reservoir quality, which describes the hydrocarbon potential of a shale. The second step is to evaluate completion quality, which describes stimulation potential. Core analysis provides the basis to help calibrate the results of these two steps. The intersection of good reservoir quality and good completion quality leads to the best chance for success in shale completion.
Kennedy, Robert L. (Baker Hughes Inc.) | Gupta, Rajdeep (Baker Hughes Ltd.) | Kotov, Sergey Vasilyevich (Baker Hughes Inc.) | Burton, William Aaron (Baker Hughes Inc.) | Knecht, William N. (Energy International Corp.) | Ahmed, Usman (Baker Hughes Inc.)
During the past six years, the technology for shale gas/oil developments in North America has seen many improvements and optimizations as the industry experiences a sharp rise in the contribution of hydrocarbons from these resources. More recently, Europe and Australia have joined the US in expanding recoverable hydrocarbons from these unconventional resources, and initial activities are on the rise in Latin America, China, Saudi Arabia and India. Despite such improvements and optimizations, a closer look at the performance reveals that not all wells are producing commercially. In addition, the hydraulic fracture stages are not all contributing within the producing wells. This scenario potentially suggests that it is important to target the field's sweet spots while dealing with shale resources (like most other hydrocarbon-bearing formations). Hence, resource development based on the current concepts of geometric placement of hydraulic fracture stages (e.g., using fixed well/fracture spacing) may not be appropriate to develop such heterogeneous unconventional resource basins. In the discussion we illustrate certain well-defined criteria that can identify the sweet spot locations within a field/basin for the optimal well placement. We further document the vital formation/zone characteristics that define the locations for hydraulic fracture stages and thus move away from the arbitrary geometric placement.
The paper will discuss the well-placement optimization process and identify the required combination of proposed special petrophysical, geochemical, and geomechanical investigations (wireline, Logging While Drilling and cores). The hydraulic fracture stage placement analysis as presented, shoulders on the need to understand the existing natural fracture system. This understanding is achieved through geophysical log measurements and comprehensive analysis of the hydraulic fracture development pattern, as well as interaction of hydraulic fractures at each stage with the natural fractures. A naturally fractured reservoir can be drained more efficiently if a complex fracture network can be created by the hydraulic fracture stimulation. This begins by drilling the well in the direction of minimum principle horizontal stress in the area.
The paper concludes by presenting examples demonstrating the practical application of some of the specific aspects of the methodology discussed and with a number of specific conclusions. In summary, the three key points to Proper Placement of Wells and Hydraulic Fracture Stages, in order to maximize the net value of an operator's asset are:
1. Begin With a Complete Understanding of the Reservoir
2. Use a Multidiscipline and Integrated Approach Across Each Phase of the Life Cycle
3. Effectively Use Modern Technology
TOTAL Abu Al Bukhoosh (TABK) has initated a well sequence with the Perro Negro 2 rig (PN2); a Jackup MODU. The rig contract started early January 2010 and may be extended till end of 2015, based on HSE and technical performances.
Since day one, it has been decided to boost the HSE performance with robust Management Leadership, Engineering HSE and ergonomics, and working on the Employees behavior. This well known drilling industry approach has been augmented by TABK decision to surpass general standards. Two additional Safety Officers providing 24 hours HSE coverage were hired by the Rig Contractor. One Rig Site Safety Advisor was mobilized by TABK. Their constant presence provides a close working relationship with the front line workers and Team Leaders. Several audits and ‘'360 Deg'' HSE initiatives were able to increase the HSE awareness of all.
PN2 has no recordable incident since 900 days. Initially, the HSE initiative and audit plans were based on the experience of the Managers offshore and onshore and not really linked to a formal ranking of the risks.
New sophisticated tools are being developed in the Oil & Gas Industry to rank risks: For example, TABK HSE and Asset Integrity Departments are working on Technological Risk Assessment and Threat Registers. Multi-yearly mitigation measures and action plans are proposed. The well recognized ‘'likelihood-consequences'' matrix has been adopted also for rig operations. It allows for highlighting the risks per area and the main population involved, ranks the areas per overall risk, and thus develops an audit/frequency plan related to those risks.
With such structured and formalized HSE strategy, risks are well captured, type and frequency of the audits are straight forward, and barriers are implemented for a residual risk ALARP.
This paper will explain in greater detail how this was achieved, the challenges that were encountered during the implementation of the tool, and how the Team intends to continue to add value in such a new HSE culture orientation.
Poor supply chain management can set the conditions for failures of catastrophic proportions, both economically and in terms of safety. It has been the root cause of several of the largest disasters in oil and gas history. Many professionals fail to recognize important gaps due to the complexity of the web of supply relationships and the number of critical interfaces that can be misaligned. Professionals from executive offices, HSE, procurement, logistics, operations, and risk management need to take four major steps to ensure a safe supply chain: 1) Establish governance & organization to ensure organizational accountability for governance and management of supply chain risk, by appointing a supply chain czar and engaging cross-functional stakeholders; 2) Adopt an internationally accepted top-level supply chain risk management framework and articulate first-level principles, including a policy on single sourcing; 3) Universally adopt formal "reinforcing?? metrics and measurement systems, including measurement of supply chain risk, Total Cost methodologies, and quantification of the cost of supplier non-compliance; and 4) Extend supply chain strategy and policies to suppliers by scanning for suppliers that excel in HSE, setting supplier expectations and targets, training suppliers, and establishing mechanisms to hold them accountable including periodic audits.
Classic View of Supply Chain Management
Supply chain management is often perceived as either a synonym for the logistics department, based on its origins 30 years ago, or as a process whose objective is to reduce operating cost and make sure supplies are available when they are needed. Either way its impact is often viewed as minor and incremental compared to much more visible activities in exploration, production, and mid and downstream operations, a perception that fails to acknowledge the significant and continuous evolution that the concept underwent since its origin 30 years ago.
Most typical supply chain challenges are economic, and come into play long after much more strategic decisions are made. Supply chain managers are responsible for avoiding cost overruns by paying suppliers the right amount - not too much, especially to sole source suppliers, and not too little, which could encourage suppliers to shift cost from one bucket to another and could jeopardize creativity and innovation. They must also make decisions that keep projects on schedule, and oil companies are even more concerned about schedule and availability than about price. In our survey (see Appendices A and B for the demographics and results of the survey, respectively), respondents cited the risk of unavailability (including schedule slippage, missed delivery deadlines, and regulatory delays) five times more frequently than price concerns.