The Stybarrow Field is a moderately sized biodegraded 22° API oil accumulation reservoired in Early Cretaceous sandstones of the Macedon Formation in the Exmouth Sub-Basin, offshore Western Australia. The reservoir is comprised of excellent quality, poorly consolidated turbidite sandstones up to 20m thick. The field lies in approximately 800m of water and has been developed with five near-horizontal producers and three water injection wells. The Stybarrow development came online at an initial rate of 80,000BOPD in November 2007.
Due to the lack of significant aquifer support, water injection was planned from start-up for pressure maintenance. Acquisition of a variety of data types have enabled key subsurface challenges to be addressed both before and during production. Structural and stratigraphic complexities influence connectivity and therefore must be fully evaluated in order to achieve optimal sweep. A feasibility study concluded that Stybarrow would be a good candidate for 4D seismic monitoring. Two monitor surveys were acquired and, along with other reservoir surveillance techniques, have been used to refine the geological model.
The first monitor survey at Stybarrow was recorded in November 2008. The results of this survey were in agreement with prior 4D modelling and supported the drilling of a successful development well in the north of the field. A second monitor survey was recorded in May 2011, three and a half years after first oil and at 70% of expected ultimate recovery. This survey is currently being analysed to determine if sweep patterns have changed.
The 4D surveys have proven to be an important tool for understanding subsurface architecture and dynamic fluid-flow behaviour. The results of both 4D seismic surveys have provided significant contributions to understanding the dynamic behaviour within the reservoir to facilitate optimal reservoir management.
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.
Low matrix permeability and significant damage mechanisms are the main signatures of tight gas reservoirs. During drilling and fracturing of tight formations, the wellbore liquid invades the tight formation, increases liquid saturation around wellbore and eventually reduces permeability at near wellbore. The liquid invasion damage is mainly controlled by capillary pressure and relative permeability curves.
Water blocking and phase trapping damage is one of the main concerns in use of water based drilling fluid in tight gas reservoirs, since due to high critical water saturation, relative permeability effects and strong capillary pressure, tight formations are sensitive to water invasion damage. Therefore, use of oil based mud may be preferred in drilling or fracturing of tight formation. However invasion of oil filtrate into tight formations may result in introduction of an immiscible liquid hydrocarbon drilling or completion fluid around wellbore, causing entrapment of an additional third phase in the porous media that would exacerbate formation damage effects.
This study focuses on phase trapping damage caused by liquid invasion using water-based drilling fluid in comparison with use of oil-based drilling fluid in water sensitive tight gas sand reservoirs. Reservoir simulation approach is used to study the effect of relative permeability curves on phase trap damage, and results of laboratory experiments core flooding tests in a West Australian tight gas reservoir are shown in which the effect of water injection and oil injection on the damage of core permeability are studied. The results highlights benefits of using oil-based fluids in drilling and fracturing of tight gas reservoirs in term of reducing skin factor and improving well productivity.
Tight gas reservoirs normally have production problems due to very low matrix permeability and different damage mechanisms during well drilling, completion, stimulation and production (Dusseault, 1993). The low permeability gas reservoirs can be subject to different damage mechanisms such as mechanical damage to formation rock, plugging of natural fractures by invasion of mud solid particles, permeability reduction around wellbore as a result of filtrate invasion, clay swelling, liquid phase trapping, etc (Holditch, 1979).
In general, for tight sand gas reservoirs, average pore throat radius might be very small and therefore it may create tremendous amounts of capillary forces. Capillary forces cause the spontaneous imbibition of a wetting liquid (in this case water) in the porous medium in the absence of external forces such as a hydraulic gradient (Bennion and Brent, 2005). This causes significantly high critical water saturation (Bennion et al., 2006). Two forces drive capillary flow (Adamson and Gast, 1997). The first is the reduction in the surface free energy by the wetting of the hydrophilic surface (wettability). In hydraulic fracturing, water in the fracturing fluid wets the surface of the pores in the rock, resulting in a decrease in the surface free energy of the pores. The other force that drives capillary flow is the capillary pressure.
Tight gas reservoirs might be different in term of initial water saturation (Swi) compared with critical water saturation (Swc), depending on the geological time of gas migration to the reservoir. Initial water saturation might be normal, or in some cases sub-normal (Swi less than Swc) due to water phase vaporization into the gas phase (Bennion and Thomas, 1996). The initial water saturation might also be more than Swc if the hydrocarbon trap is created during or after the gas migration time. A sub-normal initial water saturation in tight gas reservoirs can provide higher relative permeability for the gas phase (effective permeability close to absolute permeability), and therefore relatively higher well productivity (Bennion and Brent, 2005).
Neber, Alexander (Schlumberger) | Cox, Stephanie (Schlumberger) | Levy, Tom (Schlumberger) | Schenk, Oliver (Schlumberger) | Tessen, Nicky (Schlumberger) | Wygrala, Bjorn (Schlumberger) | Bryant, Ian David (Schlumberger)
New tools are now available to provide a rigorous and systematic play-based exploration approach to the evaluation of unconventional resources. Coupled with petroleum system modeling, this methodology offers an efficient and effective approach to identify "sweet spots?? early in the life of resource plays. Petroleum system modeling can be applied to predict the type and quantity of hydrocarbon in shale formations, as well as the proportion of adsorbed gas and geomechanical properties that are important for hydraulic fracture stimulation of shale reservoirs. Maps of these properties are then converted to chance-of-success maps for hydrocarbon generation, retention, and pore volume that can be integrated with nongeological factors, such as access and drilling depth required to reach target reservoirs. These play-based maps are expressed in probability units, so simple map multiplication provides a map of the play's overall chance of success, delineating the sweet spots. A similar methodology is applicable to evaluation of coalbed methane resources.
In this paper, we illustrate this methodology using examples from shale oil and gas shale plays in North America. These include data-rich plays from the North Slope of Alaska and data-poor plays from the northeastern and southern regions of the United States, which are more representative of many Asia-Pacific basins. We show how predictions from petroleum system modeling based on sparse data provide a good match with results of subsequent development drilling and production.
Petroleum system-based assessment of resources in place, combined with an assessment of overall play risk, enables companies to make decisions on acquisition of acreage early in the life of unconventional resource plays based on the probability of them containing economically viable resources.
Thermal maturity is an important parameter for commercial gas production from gas shale reservoirs if the shale has considerable organic content. There is a common idea that gas shale formations with higher potential for gas production are at higher thermal maturity status. Therefore estimating this parameter is very important for gas shale evaluation. The present study proposes an index for determining thermal maturity of the gas shale layers using the conventional well log data. To approach this objective, different conventional well logs were studied and neutron porosity, density and volumetric photoelectric adsorption were selected as the most proper inputs for defining a log derived maturity index (LMI). LMI considers the effects of thermal maturity on the mentioned well logs and applies these effects for modelling thermal maturity changes. The proposed methodology has been applied to estimate thermal maturity for Kockatea Shale and Carynginia Formation of the Northern Perth Basin, Western Australia. A total number of ninety eight geochemical data points from seven wells were used for calibrating with well log data. Although there are some limitations for LMI but generally it can give a good in-situ estimation of thermal maturity.
Thermal maturity and total organic carbon (TOC) are very important geochemical factors for evaluation of the gas shale reservoirs. There is a common hypothesis that gas shale layers with the higher potential for gas production (i.e. sweet spots) are located at the higher thermal maturity. Thermal maturity is an indicator for determining maximum temperature that a formation reached during different stages of hydrocarbon generation.
The first hydraulically operated completion was installed in Australia in 2004 (Guatelli et al 2004). Since then, a number of intelligent completions have been installed in offshore Australia. The remoteness of offshore Australia, particularly in the Timor Sea area, means intervention vessels are not readily available and well interventions are costly operations. For this reason, intelligent completion is considered to be an attractive alternative, by providing a down-hole solution to actively manage the reservoir production life and delay potential water breakthrough.
The Kitan oil field is remotely located in the Joint Petroleum Development Area (JPDA) between East Timor and Australia. The Kitan oil field production facilities consist of three vertical producing wells, subsea flowlines, risers, and one Floating Production Storage and Offloading (FPSO) facility. The wells were completed with an intelligent design and cleaned up using a rig before the FPSO arrived on location.
The intelligent completion design consists of two multi-stage hydraulic down-hole Flow Control Valves (FCVs) and three Down-Hole Gauges (DHGs) to independently control and monitor two different production zones. The FCVs have a total of 8 positions (fully opened, fully closed and 6 intermediate choke positions).
It is planned to close the lower FCV to shut off water production from the lower zone while the upper FCV remains fully opened over the field life. The different FCV choke positions were utilized during the field startup and during the early stages of production while the water cut was still low, to overcome unforeseen technical limitations in the production system, and to optimize hydrocarbon production.
This paper describes various aspects of the Kitan oil field intelligent well completion from design through installation and field startup to early stage of production operations, and includes technical problems encountered during the field startup as well as lessons learnt.
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.
Fractal and power law distributions have been found in the past to be useful for modeling some reservoir properties following the assumptions of constant shape and self-similarity. This study shows, however, that pore throat apertures, fracture apertures, petrophysical and drill cuttings properties of unconventional formations are better matched with a variable shape distribution model (as opposed to constant shape). This permits better reservoir characterization and forecasting of reservoir performance.
Pore throat apertures, fracture apertures, petrophysical properties and drill cutting sizes from tight and shale reservoirs are shown to follow trends that match the variable shape distribution model (VSD) with coefficients of determination (R2) that are generally larger than 0.99. The good fit of the actual data with the VSD allows more rigorous characterization of these properties for use in mathematical models. Data that could not be described previously by a single equation can now be matched uniquely by the VSD. Examples are presented using data from conventional, tight and shale formations found in Canada, the United States, China, Mexico and Australia.
In addition, the study shows that the size of cuttings drilled in vertical and horizontal wells can also be matched with the VSD. This allows the use of drill cuttings, an important direct source of information, for quantitative evaluation of reservoir and rock mechanics properties. The results can be used for improved design of stimulation jobs including multi stage hydraulic fracturing in horizontal wells. This is important as the amount of information collected in horizontal wells drilled through out tight formations, including cores and well logs, is limited in most cases.
It is concluded that the VSD is a valuable tool that has significant potential for applications in conventional, low and ultra-low permeability formations and for evaluating distribution of rock properties at the micro and nano-scale.
Fractal geometry was introduced by Mandelbrot (1982) in his seminal work "The Fractal Geometry of Nature.?? He indicated that this type of geometry applies to many irregular objects in nature. Since then, fractals have been shown to be useful in many disciplines including geology, petroleum engineering, earthquakes, and economics to name a few. In geology, the approach has been used, for example, to evaluate the distribution of natural fractures in outcrops and reservoir rocks; also for evaluating stratigraphic units. In petroleum engineering, they have been used in efforts to capture the distribution of natural fractures for well test analysis. In the case of telluric movements, fractals have been used to evaluate very small to very large earthquakes. In economics, fractals have been used to analyze the distribution of income amongst populations. In the case of the oil and gas industry as a whole, fractal geometry has been used for estimating the spatial distribution of hydrocarbon accumulations (Barton and Scholz, 1995).