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.
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.
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.
The Pyrenees Development comprises three oil and gas fields: Ravensworth, Crosby and Stickle. The fields are located in production licenses WA-42-L and WA-43-L, offshore Western Australia, in the Exmouth Sub-basin and are operated by BHP Billiton (Fig. 1). Eighteen subsea wells, including 14 horizontal producers, 3 vertical water disposal wells and 1 gas injection well have been constructed to date and additional wells are planned for infill and to develop additional resources. First oil was achieved during February 2010 and production exceeded 50 million barrels in November 2011.
The Pyrenees fields are low relief, with oil columns of approximately 40 metres within excellent quality reservoirs of the Barrow Group. The 19° API crude has moderate viscosity, low gas / oil ratio (GOR), and a strong emulsion forming tendency which makes oil/water separation and accurate well test metering difficult. Early in the project design phase it was identified that the complex subsea gathering system and the need to reduce measurement uncertainties would dictate special attention to production measurement.
Subsea multiphase flow meters (MPFMs) were specified to meet the challenges of production optimization and allocation while at the same time minimizing production deferral for separator testing. Each oil producer is monitored by a dedicated MPFM. With 14 meters, Pyrenees is among the largest subsea MPFM installations worldwide.
This paper describes the process of MPFM qualification and commissioning together with their performance over 2 years in the field. We show how close cooperation between the Operator and MPFM Vendor has enabled quality rate measurements of emulsified production despite large changes in producing gas/oil ratio and water cut.
While the primary justification for Pyrenees subsea MPFMs was production allocation and optimization, interpretation of transient water cut and GOR data proved valuable for production and reservoir engineering applications. Examples of proactive reservoir and production management including optimizing drawdown of Inflow Control Device (ICD) equipped wells, optimizing well lineup and gas lift to commingled wells are presented.
Producing and delivering North West Australia (NWA) deepwater gas reserves to LNG plants poses unique challenges. These include extreme metocean conditions, unique geotechnical conditions, long distances to infrastructure and high reliability/availability requirement of supply for LNG plants. A wet or dry tree local floating host platform will be required in most cases. Whereas semisubmersible, TLP, Spar and floating LNG (FLNG) platform designs all have the attributes to be a host facility, none has been installed in this region to date.
This paper will address important technical, commercial and regulatory factors that drive the selection of a suitable floating host platform to develop these deepwater gas fields off NWA. Linkages between key reservoir and fluid characteristics and surface facility requirements will be established. A focus will be on the unique influence of regional drivers and site characteristics including metocean and geotechnical conditions, water depths and remoteness of these fields.
There have been 17 FPSOs producing oil in Australian waters. These facilities have been chosen because of the remoteness of the fields and the lack of pipeline and process infrastructure. Storing oil on the FPSO for offloading and shipping from the fields becomes an obvious solution. Semisubmersible, TLP or Spar platforms show little advantage in such developments.
For deepwater gas developments, the product has to be processed, compressed and piped to shore for liquefaction. As host processing facilities, Semisubmersible, TLP and Spar platforms have clear advantages over FPSOs because of their superior motion performance in the harsh Australian metocean environment and other benefits such as facilitating drilling, dry tree completion and well services. FPSOs or FSOs may be applied for storage of associated oil and condensates. For marginal and remote gas field developments, an LNG FPSO (FLNG) may be an attractive option as it eliminates long pipelines and land-based liquefaction plants.
As discussed by Dorgant and Stingl (2005), a deepwater field development life cycle following discovery usually involves five distinct phases, Figure 1. The "select?? phase occurs after a discovery has been appraised sufficiently to further evaluate it for development. It consists of evaluating multiple development concepts and scenarios and selecting the one that will most likely achieve the identified commercial and strategic goals. Selecting a floating platform and its functions for a deepwater development is an important subset of the select phase and the overall field development planning.
The process of field development planning involves a complex iterative interaction of its key elements (subsurface, drilling and completions, surface facilities) subject to regional and site constraints (D'Souza, 2009). The objective is to select a development plan that satisfies an operator's commercial, risk and strategic requirements. It entails developing a robust and integrated reservoir depletion plan with compatible facility options. The selection occurs while uncertainty in critical variables that determine commercial success (well performance, reserves) is high. One of the challenges is to select a development plan that manages downside reservoir risk (considering the very large capital expense involved) while having the flexibility to capture its upside potential.
The paper will consider the implementation of the
safety case in the oil and gas industry internationally post -Macondo and Montara.
The National Commission Report into the Deepwater Horizon / Macondo blowout stated:
"The immediate causes of the Macondo well blowout … …. that reveal such systematic failures in risk management that they place in doubt the safety culture of the entire industry. "
In their letter to Minister Ferguson on 22 March 2011, the NOPSA Board stated:
"The Montara and Macondo incidents each demonstrate technical ignorance and a poor safety culture including complacency regarding low probability, high consequence risks. There is a clear need to improve industry safety culture, accountability and leadership."
The paper will examine these criticisms and consider how the industry
needs to improve its process safety and risk management. The implementation of a safety case in the USA may only occur "in the typical rule-making process that takes up to two years" (Michael Bromwich, Director of BOEMRE). Knowledge, understanding and application of key aspects of process safety management and the safety case process are not uniform. The paper will suggest how, in this context, the safety case can be applied to achieve the required outcomes.
The paper will draw from specific findings from the Macondo and Montara incidents.
There are echoes of Piper Alpha in the performance of emergency systems on Deepwater Horizon. The inadequate application of hazardous area classification is a key issue which the paper will examine in order to provide greater understanding. Whilst in Australia, issues of consistency and quality arise with matters such as performance standards. The paper will discuss the need for a standard for "performance standards" that goes beyond current regulatory guidelines.
Overall, the paper will seek to propose a way forward for the industry in several practical areas.
The design team for the Wheatstone offshore platform successfully deployed an ‘Inherently Safe Design' (ISD) approach to engineering the gas processing complex. Through a program of initiatives focused on ISD, a substantial improvement in the safe design of the platform has been delivered.
Major accident events:
The Texas City incident in 2005 initiated the most detailed and far reaching investigation ever undertaken by the US Chemical Safety and Hazard Investigation Board (CSB) at the time. The CSB report included a recommendation that BP form an independent panel to conduct a review of the company's corporate safety culture, safety management systems, and corporate safety oversight at its U.S. refineries. This independent review was conducted and a separate report known as the Baker Report was developed, with the key conclusion being that the process safety culture was deficient.
Major incidents such as the Macondo and Montarra well blow-outs still occur. NOPSA newsletter Issue 86, February 2010 presented data on gas releases, a recognised precursor to major accident events and showed "Design problems at root of most major gas releases??.
An analysis approach to assess borehole stability following a hypothetical blowout from representative deepwater scenarios is presented. It addresses whether imposed underbalanced conditions cause sufficient instability that the borehole bridges-over and the well kills itself. The approach uses a series of interrelated analyses: (i) analyses of the kick and blowout development are performed predicting how bottom pressure and in-flow velocity changes over time; (ii) underbalanced wellbore failure in exposed shales and sands is then determined; (iii) cavings and produced sand volumes are calculated from the estimated failure zone, and the transport of these materials in the borehole is determined from the predicted hydrocarbon flow rates; and (iv) bridging tendency is assessed by considering the concentration of cavings in either the enlarged borehole or in flow-paths within the well casing or annuli.
To the best knowledge of the author, the proposed analysis presents the first in-depth study of transient wellbore instability, sand / cavings transport and bridging tendency during a blowout. Analyses applied to a typical deepwater blowout scenario suggest that bridging leading to self-killing can occur only in a small number of situations. This differs from the more widely published data from shallow water Gulf of Mexico Shelf wells which show that self-killing is likely in shallow-hazard scenarios.
Important conclusions from the study are: (1) bridging and self-killing can occur in kicks resulting from a catastrophic loss of riser integrity, due to the loss of the riser margin causing underbalanced conditions in openhole sections of the borehole; and (2) bridging and self-killing is more likely to occur in a well control event that develops while drilling-ahead, due to plugging of the borehole/drill-pipe annulus. Bridging is less likely to occur if a kick develops with the drill-pipe not in the open-hole interval. For self-killing to happen this study concludes that it has to occur during the time that the kick is developing - i.e. before hydrocarbons reach the wellhead. Once the kick has fully developed into a blowout it is predicted that typical high productivity deepwater reservoirs will have attained sufficient borehole flow velocity (in the absence of major constrictions to flow) that spalled or produced formations will be transported from the wellbore without bridging. Once a blowout has occurred, therefore, it is largely too late to consider future bridging as a means of terminating the flow, at least in the short-term.