The high-profile blowout at Macondo well in the US Gulf of Mexico, brought the challenges and the risks of drilling into high-pressure, high-temperature (HPHT) fields increasingly into focus. Technology, HSE, new standards, such as new API procedures, and educating the crew seem to be vital in developing HPHT resources. High-pressure high-temperature fields broadly exist in Gulf of Mexico, North Sea, South East Asia, Africa, China and Middle East. Almost a quarter of HPHT operations worldwide is expected to happen in American continent and the majority of that solely in North America. Oil major companies have identified key challenges in HPHT development and production, and service providers have offered insights regarding current or planned technologies to meet these challenges. Drilling into some shale plays such as Haynesville or deep formations and producing oil and gas at HPHT condition, have been crucially challenging. Therefore, companies are compelled to meet or exceed a vast array of environmental, health and safety standards.
This paper, as a simplified summary of the current status of HPHT global market, clarifies the existing technological gaps in the field of HPHT drilling, cementing and completion. It also contains the necessary knowledge that every engineer or geoscientist might need to know about high pressure high temperature wells. This study, not only reviews the reports from the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) and important case studies of HPHT operations around the globe but also compiles the technical solutions to better maneuver in the HPHT market. Finally, the HPHT related priorities of National Energy Technology Laboratories (NETL), operated by the US Department of Energy (DOE), and DeepStar, as a strong mix of large and mid-size operators are investigated.
Poedjono, Benny (Schlumberger) | Beck, Nathan (Schlumberger) | Buchanan, Andrew (Eni Petroleum Co.) | Brink, Jason (Eni Petroleum Co.) | Longo, Joseph (Eni Petroleum Co.) | Finn, Carol A. (U.S. Geological Survey) | Worthington, E. William (U.S. Geological Survey)
Geomagnetic referencing is becoming an increasingly attractive alternativeto north-seeking gyroscopic surveys to achieve the precise wellbore positioningessential for success in today's complex drilling programs. However, thegreater magnitude of variations in the geomagnetic environment at higherlatitudes makes the application of geomagnetic referencing in those areas morechallenging.
Precise, real-time data on those variations from relatively nearby magneticobservatories can be crucial to achieving the required accuracy, butconstructing and operating an observatory in these often harsh environmentsposes a number of significant challenges. Operational since March 2010, theDeadhorse Magnetic Observatory (DED), located in Deadhorse, Alaska, was createdthrough collaboration between the United States Geological Survey (USGS) and aleading oilfield services supply company. DED was designed to produce real-timegeomagnetic data at the required level of accuracy, and to do so reliably underthe extreme temperatures and harsh weather conditions often experienced in thearea.
The observatory will serve a number of key scientific communities as well asthe oilfield drilling industry, and has already played a vital role in thesuccess of several commercial ventures in the area, providing essential,accurate data while offering significant cost and time savings, compared withtraditional surveying techniques.
The Ichthys LNG Project
INPEX has begun construction of one of the world's largest oil and gas projects following the Final Investment Decision (FID) on the US $34 Billion Ichthys LNG Project in Australia on 13 January 2012. The Ichthys LNG Project is a joint venture between INPEX (Operator) and Total with Tokyo Gas, Osaka Gas, Chubu Electric and Toho Gas.
The Ichthys Field is situated in the Timor Sea approximately 200 kilometers off the Western Australian coast and over 800 kilometers from Darwin. Three exploratory wells drilled in 2000 and 2001 resulted in the discovery of an extremely promising gas and condensate field with resource estimates from two reservoirs totaling approximately 12TCF of gas and 500 million barrels of condensate. Conceptual studies, FEED and ITT followed and development leading to sanctioning of the Ichthys LNG Project by INPEX and Total.
Gas from the Ichthys Gas-Condensate Field in the Browse Basin will undergo preliminary processing offshore to remove water and extract condensate. The gas will then be exported to onshore processing facilities in Darwin via an 889 kilometer subsea Gas Export Pipeline (GEP). Most condensate will be sent to a Floating Production Storage and Offloading (FPSO) vessel for stabilization and storage prior to being shipped to global markets. The Ichthys LNG Project is expected to produce 8.4 million tons of LNG and 1.6 million tons of LPG per annum, along with approximately 100,000 barrels of condensate per day at peak.
Production from 20 subsea wells in the first phase - 50 will be drilled in total - will be sent to the Central Processing Facility via 8?? rigid lines connected to flexible risers. The flexibles will be supported by a 110 meter high jacket type riser support structure. You see, no aspect of the Ichthys LNG Project is small.
Effluents will be separated on the Central Processing Facility (CPF), a semi-submersible floater. Gas will be dried and compressed prior to being sent ashore via a GEP. Compression will be from four compressors, designed for 590.7 MMSCFD. Following initial treatment, most liquids will be transferred from the CPF to the nearby FPSO for processing and storage. The 330 meter-long FPSO will be a weather-vaning ship-shaped vessel that is permanently moored on a non-disconnectable turret. It has been designed with a storage capacity of nearly 1.2 million barrels. Loading of two offtake tankers in tandem will be possible from the FPSO.
The oil & gas industry is constantly adapting to change, be it related to price, technology or market demand. High prices of crude oil and advances in technology have allowed producers to access resources previously out of reach, and extract maximum value from these resources. With this, however, operational risk is significantly augmented - both upstream and downstream. In order to cope with this increased risk, it is vital that oil & gas companies have a process safety management (PSM) system that fully integrates management of change methodologies.
DuPont has developed a PSM system that fully integrates change management across multiple facilities, among personnel and in light of technological advancement. While these must be considered singularly, it is also important for companies to build a holistic system that accounts for the interdependent nature of operational systems, and thus address process safety from every possible angle - training and skill development to hazard analysis and maintenance. However, as only a limited number of procedures [PW1] can be universally applied to cope with changing process conditions, this paper will also detail the means through which companies can develop customized solutions for specific conditions and contexts.
By developing a model that can effectively manage change, it is possible for oil & gas companies to not only avoid catastrophic incidents, but also increase the overall safety of an operation, while concurrently maximizing efficiency, cost-effectiveness and quality.
The extraction and processing of oil and gas is a highly technical mechanical operation that involves volatile and corrosive substances in often extreme conditions. As such, it is vital for companies within the oil & gas sector to develop a holistic PSM system that can successfully manage process safety, while remaining agile enough to respond to specific issues, and any changes thereof.
Carbonate reservoirs are commonly heterogeneous and their reservoir quality results from complex interactions between depositional facies and diagenetic processes. The Diagenetic Diagram is a powerful tool that helps in the characterization of the diagenetic processes that have affected the reservoir. From this knowledge, it is possible to significantly improve the understanding of the reservoir's pore system and permeability distributions, which are key factors for development optimization and production sustainability.
A multi-scale and multi-method study (petrography, blue-dye impregnation, selective staining and porosity determination) of Middle Jurassic carbonates from the Lusitanian Basin (Portugal) has been undertaken, to find the best systematic approach to these reservoirs. It has involved thorough diagenetic characterization of each lithotype (lithofacies, texture, porosity, qualitative permeability assessment and diagenetic evolution). The study area was selected based on its excellent and varied exposures of carbonate facies and availability of core.
Methodological and terminological challenges were faced during the study, especially dealing with data coming from several scales (macro, meso, and micro). In order to overcome these challenges, a diagenetic diagram was developed and applied to the selected rocks. It is a tool that allows the integration of data coming from outcrops, hand samples, cores, cuttings, thin sections, and laboratory experiments.
This is carried out in a dynamic, guided, systematic, and rigorous way, enabling the evaluation of the relationship between facies, diagenetic evolution and pore systems. The latter are characterized regarding size, geometry, distribution, and connectivity. This enables the identification and characterization of permeability heterogeneities in the rocks. It was concluded that the main porosity class (i.e. secondary) was created by diagenetic processes.
The proposed method has strong application potential for: detailed characterization and understanding of porosity and permeability in carbonate reservoirs, from a diagenetic evolution and fluid flow perspective (e.g. SCAL and pore system description); definition of diagenetic trends for modeling petrophysical properties and rock types. In this regard, the method is being applied to a Valanginian carbonate reservoir in Kazakhstan, and some preliminary results are presented in this paper. Refining this technique may be helpful for similar carbonate studies, enhancing the results of typical diagenetic studies by improving the characterization of reservoir properties at various scales, thus contributing to a more sustainable exploitation of hydrocarbon reservoirs.
Mosher, Charles C. (ConocoPhillips) | Keskula, Erik (ConocoPhillips) | Kaplan, Sam T. (ConocoPhillips) | Keys, Robert G. (ConocoPhillips) | Li, Chengbo (ConocoPhillips) | Ata, Elias Z. (ConocoPhillips) | Morley, Larry C. (ConocoPhillips) | Brewer, Joel D. (ConocoPhillips) | Janiszewski, Frank D. (ConocoPhillips) | Eick, Peter M. (ConocoPhillips) | Olson, Robert A. (ConocoPhillips) | Sood, Sanjay (ConocoPhillips)
The high decline rate observed in over pressured shale has attracted the attention of the industry, and better well management procedures for long term productivity improvement are still evolving. Operators are recognizing some benefit in controlled rate (controlled drawdown) production as one way of improving well performance for the wells in over pressured stress sensitive formations.
During uncontrolled rate production because of high drawdown, the permeability in stress sensitive shales decays faster because of increased stress. Often high initial gas rate is accompanied by high decline rate as the permeability reduction takes effect. In addition, proppant could also be produced back, crushed or embedded in the formation. However, controlled rate production minimizes the rate decline, albeit at reduced initial gas rate. Modelers resort to using different stress permeability decay coefficients for these two production strategies. Higher values are assigned to uncontrolled rate production to produce lower EUR. This approach, although convenient, requires different permeability versus stress tables depending on the production strategy.
Porosity and pore volume reduction in shales could be as high as 20 percent due to changes in net stress. The pore volume reduction provides in situ energy for gas recovery. The increased rate of permeability decay due to changing in situ stresses reduces the effectiveness of pressure support from pore volume reduction as fractures close under stress.. Controlled rate production strategy slows down permeability decay rate and this enables better use of pore volume energy. The pore volume consideration could provide additional gain to EUR for controlled rate.
Our analytical simulation model couples geomechanics permeability and porosity stress coefficients and evaluates well performance under moderate and low net stress sensitivity. Haynesville and Marcellus shales were evaluated. The importance of pore volume stress effect from the stand point of well performance evaluation and reservoir characterization is assessed.
Napalowski, Ralf (BHP Billiton) | Loro, Richard (BHP Billiton) | Anderson, Calan Jay (BHP Billiton) | Andresen, Christian Andre (ResMan AS) | Dyrli, Anne Dalager (ResMan AS) | Nyhavn, Fridtjof (ResMan AS)
This paper describes the interventionless approach that was successfully executed during the Pyrenees early production phase to identify the timing and location of water breakthrough. Chemical inflow tracers were installed in key production wells within the lower completion along the horizontal production sections. Results from this work have supported the reservoir simulation history matching process and confirmed the performance of the inflow control devices (ICDs). These data in conjunction with the real time rate information from subsea multiphase meters has allowed proactive reservoir and production management that has contributed to the early identification of additional infill opportunities.