A subsea HIPPS (High Integrity Pressure Protection System) is an effective tool to reduce the overall CAPEX of a system by limiting the pressure downstream equipment may experience. While there are challenges associated with implementing this system, proper HIPPS design focuses on the safety and reliability of the entire system from reservoir to topsides. A HIPPS can allow the integration of high pressure wells into low pressure systems, thus expanding the capabilities and life of equipment that may already exist. In order to ensure the safety and reliability of the HIPPS, rigorous testing and compliance with regulatory bodies are necessary.
This paper presents a summary of the design criteria of a subsea HIPPS, the benefits of proper HIPPS implementation, and the challenges that must be met. Despite these challenges, it is both plausible and feasible to integrate future high-pressure systems into low-pressure systems by implementing a HIPPS to protect against the overpressure of low-pressure equipment.
The first Tension Leg Platform (TLP) was installed in 1984 to develop the Hutton field in the Central North Sea in about 500 ft of water. It successfully demonstrated the ability of a floating platform tethered to the seabed to drill and produce with surface trees. In the ensuing years, twenty three additional TLPs have been installed and five more sanctioned, in most major deepwater producing regions around the world, in water depths down to 5,200 ft.
The TLP today is a mature and proven deepwater production platform and is routinely included as a platform concept building block for many deepwater prospects during field development planning for dry or wet tree scenarios. This paper will present a retrospective of TLP development that includes:
This paper highlights the progression of TLP technology and contracting strategies of the installed and sanctioned TLPs. The paper provides a snapshot in time to capture the evolution and current state of TLP technology. The impact on TLP design in Gulf of Mexico (GoM) from the new API RP 2T is demonstrated via an example of a pre and post Katrina sanctioned TLP.
TLP System and Hull Configuration Overview
The TLP is one of several mature floating production platforms in the Offshore Industry's arsenal to enable development of deepwater fields in any openwater offshore producing region in the world. It was conceived in the 1970s as a means of enabling direct vertical access to wells in water depths beyond the commercial reach of fixed and compliant platform capabilities. Fundamentally, it consists of a buoyant hull, which supports the topsides and well systems, anchored by rigid tendons to a seabed foundation to restrain vertical motions in waves. Excess buoyancy pretension the tendons that limit the horizontal offset to a prescribed watch circle. The heave restraint enables production wells to be tied back to the TLP deck by tensioned vertical risers to "dry?? trees. The dry tree facilitates easy downhole access for well intervention and reservoir management to maximize hydrocarbon recovery from a reservoir. This is particularly applicable for highly compartmentalized and stacked reservoirs. It also simplifies running and retrieval of downhole electric submersible pumps (ESP's) to further boost well production rates and ultimate recovery. Major TLP components are illustrated in Fig. 1.
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 objective of the work is to assess the feasibility of a tension legplatform (TLP) dry tree unit (DTU) with tender-assisted drilling (TAD) for theharsh metocean conditions offshore North West Australia, characterized by theoccurrence of tropical cyclones and persistent swells. Making use of thedrilling tender vessel's accommodation, power generation, mud pumping, cleaningand storage facilities etc. can reduce the production platform topsides weightby up to 3,000 tonnes. Such weight and associated cost savings could becomeenablers for some of the deepwater gas field developments offshore WesternAustralia.
A TLP configuration is evaluated as the DTU in a water depth of 500 m. The TLPis sized for a specific payload for gas production. A typical 6-columnsemisubmersible is configured as the drilling tender vessel (DTV), for which apreliminary TAD mooring system is defined. Hydrodynamic models for the combinedDTU/DTV systems are developed and used to perform extreme response andoperability analyses.
The coupled TLP/DTV TAD system is analyzed in 1, 10 and 100-year return periodenvironments. It is shown that the DTU and DTV vessel can be safely mooredtogether by hawsers without collision in up to 10-year return cyclonic stormevents. This means that the mooring system operability of up to 99.97% isachievable.
In environmental conditions harsher than 10-year return cyclonic storms, theDTV will be disconnected from the DTU and a full 8-point mooring pattern willbe required to moor the DTV to survive up to 100-year return periodcyclones.
This paper presents the results of study work Granherne recently performed for an offshore carbon dioxide (CO2) Enhanced Oil Recovery (EOR) Project in the North Sea. In particular process design complexities are discussed for a new topside module comprising oil/gas separation, associated gas compression, dehydration with dense phase gas streams rich in CO2.
The importance of thermodynamic Equation of State (EOS) selection is highlighted, specifically for compressors and pumps in dense phase CO2 service. The selected HYSYS EOS results were benchmarked against a highly reliable Reference Fluid Thermodynamic and Transport Properties (REFPROP) database developed by National Institute of Standards and Technology (NIST). The comparisons are presented for compressibility, heat capacity, the heat capacity ratio and the enthalpy change across each compressor stage.
For the design of the gas dehydration unit, the experimental water equilibrium concentrations are compared with those predicted by commercially available simulators for a CO2-Water system. The HYSYS EOS did not model the acid gas-water system as accurately as Aqualibrium. The degasser flows for specifying the capacity of the LP Compression Train were under predicted by HYSYS EOS. The accuracy was improved by using the proprietary NRTL-SRK-Henry's Law model in ASPEN PLUS.
The CO2 venting and depressurisation philosophy developed to avoid the formation of solid CO2 in the distribution headers is outlined. Also, the environmental aspects of CO2 rich gas cold venting versus flaring with assist gas is discussed.
The paper further highlights the technical design complexities compared to onshore CO2 EOR.
The hazards of oil and gas facilities are well known to the league of operators, hardware providers, designers and lieges of contractors and consultants who work supporting the industry. Since Piper Alpha in 1988 safety is and has been a priority and the driver of countless modifications to ensure the well being of personnel in operating environments.
The oil and gas industry overall has shown a declining trend in fatalities and injury rates around the world demonstrating that learnings from mistakes have been taken on board so that they are not to be repeated. With the advent of deepwater production, bigger equipment items, changing field conditions and extended field lives, the financial rewards have become potentially even greater than ever to the industry, but at what risk?
The drivers are changing just like in the Le Mans 24 hour car race, the impact of safety risk is less prevalent as people are removed and other risks comes to the fore.
This paper discusses some of the issues that Granherne and the author has experienced in its provision of safety services to the oil and gas industry and provides an insight into how safety principles can still be focused even without the people present.
Before looking at some of the observed trends and risk challenges in the oil and gas industry it is important to ensure that some key definitions are understood.
Risk Trends and Challenges for Today's Industry
The following describes observed risk trends in the oil and gas industry that Granherne and the author have seen through consulting. Each risk trend is identified and key issues highlighted in order to promote discussion of some current and anticipated future issues.
Safety in Design
Designing a facility that is functional efficient and safe at reasonable cost has always been at the heart of the design process. Designers have always been aware of accidents at other facilities and have endeavoured to incorporate these learning's to ensure that the same accident does not happen again. It has been important since the advent of the Safety Case in Australia in 1995 that these learnings should always be incorporated into other operations. This philosophy is highlighted in both the Australian onshore Major Hazard Facility guidelines (Ref. NOHSC, 2002) and National Offshore Petroleum Safety Authority guidelines (Ref. NOPSA, 2004). This is also one of the key principles in the United Kingdoms HSE assessment for offshore facilities (Ref. UKHSE, 2006).
Current capabilities with coiled tubing and slickline are insufficient to provide complete well intervention support to deep, high-pressure wells drilled from a floating vessel in a deepwater Gulf of Mexico (GOM) field. These intervention technologies limit the allowable departure of proposed wells to 8,500 ft and often restrict intervention scope to "dead well?? operations.
A hydraulic workover (HWO) system is being developed to support a deepwater GOM field. The system will be located under the rig floor with heave compensation provided by the rig's riser tensioning system. HWO control will be achieved using a remote panel and operations will be observed from the driller's cabin on closed-circuit television (CCTV). To keep the stack-up height as short as possible, the surface pressure control equipment (PCE) will utilize special unitized body valves. The PCE will be stored on a purpose-built fixture where it can be pressure and function tested prior to rig up. The surface and subsea PCE will include shearing and sealing capability for the largest diameter pipe to be used.
The HWO solution provides a high-strength conveyance method to intervene and operate under pressure from a floating vessel in deep, high-pressure reservoirs. The customized HWO extends intervention capabilities to a departure of 15,000 ft (28,800 ft MD) under 8,800-psi wellhead pressure.
The HWO provides features that enhance personnel safety and economic efficiency. The advantages of a sub-floor HWO include: (1) improved safety by removing personnel from an elevated workbasket exposed to pressure and erratic movement, (2) more efficient operation through use of the rig's regular hoisting equipment, (3) elimination of the need to pull production tubing when extending existing wells, and (4) complete reservoir accessability without the need for satellite wells.
HWO units have seen limited use in floating applications. This is in part because the motion characteristics of floating facilities present issues with the use of conventional snubbing equipment. These issues are particularly significant when intervention is required on wells with subsea trees. The design of a HWO system for floating operations must consider the motions and environmental loads inherent to these operations.
Historically, several HWO system designs have been considered for use in floating operations. These systems include deck-mounted and derrick-suspended systems. All of the systems known to have been used to date have used above-the-floor snubbing equipment.
In 1998, an HWO job was performed on a subsea well from a GOM semisubmersible floating drilling and production facility. In this 2,100-ft water depth application, an above-the-floor-deployed HWO unit was motion compensated with the drillstring-compensation system. A high-pressure riser consisting of 5-in. drillpipe was run inside a standard drilling riser. The system design was intended to account for a relative motion of ±5 feet between the rig and riser.1
In 2007, the intervention challenge is greater. Increasingly, new technology allows GOM field exploration in deeper, higher pressure reservoirs. Economics demand that creative well intervention services continue to be employed to safely extend to unproven reserves in deep, high-pressure zones.
To improve access to these reserves, it is now desired to develop a rig-assist HWO unit that can be deployed below the rig floor of a deepwater production and drilling facility. Typically, such offshore facilities are not designed with HWO intervention capability in mind. Space is often at a premium and devoted primarily to production requirements. Standard rig-assist HWO units often require a sizeable footprint above deck for well intervention work, and the space available below the floor of a floating rig does not easily accommodate a large HWO equipment package. As a result, a custom-engineered HWO design is being developed (see Fig. 1).
A deepwater, high-pressure field located about 90 miles offshore Louisiana in over 6,000 ft of water is being developed using a permanently moored semisubmersible production and drilling facility. All the wells feature subsea completions from locations surrounding mud-line production manifolds.