The intent of this work is to outline the workflow that engineers can apply in the selection and modelling of inflow control devices (ICDs) for use in completion design. It provides a step-by-step guide and examples of how to address the key challenges in the field of modelling of ICDs, namely: the choice of ICD technology that is most suitable for the particular well; the process of building a custom ICD performance model and import into the reservoir simulator; considerations in setting up the simulation model; and, verification of the results. The paper highlights the risk of using empirical ICD models, available in reservoir simulators, in the early stages of evaluating inflow control technology. It then demonstrates that the decision on whether or not an inflow control is required, and what type, can be made without resorting to these built-in empirical models in reservoir simulators. The paper introduces a new approach to evaluation, comparison and modelling of inflow control devices of different types and geometry. Focused on simplicity and accuracy, the method of ICD characterisation is described, as is how to use this characterisation to generate input to the reservoir simulator. A method for verification of the output from the reservoir simulator is also presented. The application of this modelling approach is illustrated through a case study on evaluating inflow control technology in a mature oil reservoir.
Because of the substantial cost involved, subsea environments demand technologies which improve efficiency. This statement is particularly true in marginal developments. In such scenarios, multilateral completions have played an integral part in improving field economics through improved well performance and reducing both field and operating costs to a point where the field development is financially appealing. In the northwest shelf of Australia, there have been four major oil field developments to date which have been based either entirely or partially on multilateral completions. This paper describes the evolution of multilateral completions throughout the past 10 years in Australia for two such developments, outlining the efficiency and operational gains during that time period.
Sand face completion techniques in Australia's northwest shelf vary from conventional standalone screens (SAS) to more sophisticated sand control methods, such as gravel packing. For multilateral wells in this region, even though gravel packs have been installed in other regions, developments to date have been limited to oil producers with SAS with inflow control devices (ICDs) and swell packers for compartmentalization. Nonetheless, the process of constructing and completing a subsea multilateral completion can be complex, and often trip intensive. Early multilateral field developments borrowed technology from the Norwegian northwest shelf; however, as such, the completions were not optimized for the specific Australian operating environment. Following the first successful subsea multilateral field developments in Australia, customized technology began to be developed to address and improve completion efficiencies. Specifically, several global and regional first installations were implemented between 2014 and 2016 that reduced dedicated installation time by 42% and helped reduce or eliminate operational risks.
In addition to discrete technologies, well architectures have also been revisited to further the economic advantages of multilateral completions. Trilateral wells, where three laterals penetrate the reservoir, are now commonplace in subsea developments in Australia. The custom solutions developed throughout the past 10 years demonstrate not only industry maturity, but also region specific advancements in multilateral completion technology.
Australia's history of multilateral completions is a success story, highlighting an industry's adoption of new technology and appetite for improvement on a broader scale. In ten years, the step change in multilateral completion has been appreciable. The result of a decade worth of improvement and customization is a fit-for-purpose, reliable, robust and efficient completion practice.
Naveed, Muhammad (Schlumberger) | Kirthi Singam, Chandrasekhar (Schlumberger) | Viandante, Mauro (Schlumberger) | Ali Malik, Kashif (Schlumberger) | AKhmadeev, Vadim (Schlumberger) | Jury, Ben (Woodside Energy) | Belson, Will (Quadrant Energy) | Wroth, Andy (Vermilion Oil and Gas Australia)
It is widely recognized in the industry that 30m survey intervals are too large to capture the true trajectory of the directional borehole and can result in significant True Vertical Depth (TVD) errors. This is particularly true when drilling with motors or geosteering in reservoirs with tight-TVD tolerance. Based on experience with horizontal wells drilled in North West Shelf (Vincent, Wandoo and Coniston drilling campaigns), a new technique of high definition surveying (HDS) was introduced.
The North West Shelf (NWS) in Australia imposes significant challenges for maintaining constant directional control while drilling in sand layers, which can be unconsolidated and include or traverse faulted or fractured zones. In such formations, TVD control in horizontal wells is a challenge. To improve control, extra surveys would be needed to reduce the vertical uncertainty; this process would be very time-consuming iand adds a risk of stuck pipe and hole washout.
Additionally, as the field become more congested through infill drilling, the risk of collision with nearby wells would increase because of poor TVD control.
The HDS gives a more accurate reconstruction of the wellbore position while drilling with respect to the pre-drilled geological model all the way out to target depth.
Reservoir mapping while drilling (RMWD) and Bed boundary mapping (BBM) services both measure the distance to nearby boundaries. These services map the form and position of reservoir boundary structure with respect to the associated well path. Therefore, the position of the reservoir structure in space is directly related to the directional wellbore survey. An inaccurate survey leads to errors in reservoir geometries and structural tie-in to the adjacent exploration and development wells. Because the wellbore is more accurately defined using HDS, so is the reservoir structure when coupled with RMWD services. This greater definition has enabled better well planning to drive maximum value extraction from reservoirs. With these features in place HDS has become an integral part for RMWD and BBM Services.
This paper illustrates the potential benefits of using HDS as a further service quality improvement component applicable to drilling horizontal wellbores and gives examples of practical implementation such as borehole tortuosity, torque and drag modelling, well placement and drilling and completion optimization.
A development campaign offshore Australia, with a total of 15 laterals in a challenging geological environment, has been successfully completed by Quadrant Energy. The main objectives were to geosteer and place the well path at an optimum standoff from the oil/water contact (OWC), while drilling at the interface of the gas/oil contact (GOC), when present, and at 1-1.5m TVD from the reservoir top when not.
The field is characterized by a series of transverse and longitudinal seismic and sub-seismic faults that bisect hydrocarbon-bearing sands which represent the greatest challenges in this development campaign. Evidence from exploration wells showed a thin column of heavy oil and a gas cap in the fault-bonded reservoir. A new multi-disciplinary methodology not only enabled Quadrant Energy to achieve its development objectives, but to develop a full subsurface picture of the Coniston field reservoir.
The use of the Reservoir Mapping-While-Drilling (RMWD) combined with Bed Boundary Mapping Tool (BBMT) and Multi-Function LWD services enabled the laterals to be placed at 1-2m TVD below the reservoir top or gas cap, when present, even in highly faulted sections. In addition to this precise placement the extreme depth of investigation of the RMWD service, in conjunction with the real-time multilayer inversion capability, constantly mapped the OWC at a distance up to 19m TVD below the wellbore. While drilling, different qualities of reservoir sands were identified and enabled the extensions of the wells’ TDs based on reservoir properties. The distance to boundary information, provided in real-time by the RMWD service, was used in real-time by the Quadrant Energy geology and geophysics team to update and validate the seismic model that provided increased confidence in the reservoir model and a more precise planning for future development wells.
This paper will illustrate the use of the latest LWD RMWD technology in a challenging geological environment. The paper will explore the close collaboration, teamwork, and integration necessary to drive innovation and demonstrate the outcomes of this successful campaign which have not only exceeded the development goals, but have also generated a full 3D view of the reservoir.
Two methods are commonly used to produce window exits in multilateral wells. One implements premilled window technology, while the other involves steel casing milling. Steel casing milling generates steel cuttings that can be challenging to circulate to surface during wellbore cleanout and can hinder equipment in subsequent downhole operations. Premilled windows eliminate steel debris; however, they require that the main bore casing string be oriented. This paper describes an additional approach that does not create steel milling debris nor requires orientation of the casing string, which can result in significant time savings and risk reduction.
This approach involves an all-aluminum casing exit joint (hereon referred to as ACE joint) coupled to a lower coupling with a latch profile in which service tools can be landed to perform junction construction. This new technology, including design rationale, development, installation procedures, subsequent testing, and field trial results are discussed within this document. The ACE joint was designed, manufactured, and deployed in a multiwell, TAML 5 multilateral field development containing bilateral and trilateral wells. To create the window exit, the ACE joint and latch coupling are made up to the main bore production casing and cemented in hole. An orientation tool is then run in hole (RIH) and latched into the joint latch coupling, obtaining coupling orientation. The whipstock and mill assembly is then configured at surface to the desired millout orientation, RIH, and latched into the ACE joint for subsequent milling operations.
Lab testing has been performed to qualify the ACE joint for suitable milling performance, corrosion resistance, and drilling wear resistance; all with positive results. Field installations have also been successful, with bi and trilateral wells having laterals exceeding 2000 m in length being created without problem. The tests and field installations demonstrate the ACE joint is now a proven technology, confirming the window geometry post millout to be acceptable for lateral drilling and completion operations.
This new approach to window millout technology represents an improvement to existing steel casing milling technology, providing a more suitable solution for removal of milling debris and a more simple installation process.
Sankoff, Roumen Dimitrov (Apache Energy Ltd.) | Di Martino, Gianluca (Apache Energy Ltd.) | MacDonald, Shona (Apache Energy Ltd.) | Marshall, Craig Scott (Apache Energy Ltd.) | Smith, Anthony (Apache Energy Ltd.)
The development of heavy oil accumulations presents difficult engineering, technological and geological challenges that need to be overcome to produce economically viable projects. Even a large oil accumulation can be deemed unattractive for development in cases that combine a high cost environment with complex geological setting and unfavorable fluid dynamics. This paper highlights the challenges and presents the subsurface solutions that unlocked the value of an offshore heavy oil accumulation, 32 years after it was first discovered. Within the context of the overall development plan, the paper describes:
1. The design of the offshore well test that delivered 11,244 bbl/d 15.7oAPI oil and proved the production capacity of the reservoir and the conceptual well design.
2. Workflow for confirming the existence of a compositional gradient and characterization of a biodegraded oil column.
3. A novel approach to evaluation of inflow control devices (ICD) and its implementation in the well design.
4. An ICD modelling tool developed specifically for direct comparison of different ICD geometries.
The paper also presents the field history to date - from the early failures in recovering hydrocarbons using conventional methods, through to the enabling technologies that made Coniston and Novara a viable project.
Coniston and Novara reservoirs are located in permit WA-35-L, offshore Western Australia (Figure 1). Apache holds 52.5% working interest and operates the permit on behalf of a joint venture with INPEX which holds 47.5%. The joint venture acquired the permit in 2009, 27 years after the field was discovered with the drilling of Novara-1 in 1982. The fields are 45 km from the coast of Western Australia (Figure 1) in 380 m water depth and will produce 14-16oAPI oil from the Barrow Group formation.
The reservoir contains a thin oil column between a small gas cap and strong bottom-drive aquifer. The oil will be produced via subsea tie-in to an existing production system and a floating production, storage and offloading facility (FPSO), the Ningaloo Vision (NV), located approximately 10 km away.
The project was challenged by (1) unproven well and reservoir capacity to deliver production at commercial rates, (2) heavily compartmentalized low relief reservoir structure, (3) water and gas coning affecting recovery from a thin oil column, (4) a strong bottom-drive aquifer impacting the wells’ drainage area and (5) flow assurance and operability issues due to long distance subsea tie-back.
Production at commercial rates from each reservoir was demonstrated in the early phase of the appraisal campaign. The flow tests met all objectives, and set a record for the region with the Coniston-2H well testing at 11,244 bbl/d of 15.7oAPI oil. The successful production tests were followed up with further appraisal wells to delineate the structure. The results from the appraisal drilling revealed: a low-relief structure, complex fault network, lateral variation in the fluid contacts.
Hill, Robin Andrew (BHP Billiton Petroleum Americas Inc.) | O'Halloran, Gerry (BHP Petroleum) | Napalowski, Ralf (BHP Billiton) | Wanigaratne, Bimal (BHPBilliton) | Elliott, Alison Anne (BHP Billiton) | Jackson, Mark Alan (BHP Billiton Petroleum)
The Stybarrow Field is a moderate size biodegraded oil accumulation reservoired in early Cretaceous slope turbidite sandstones of the Macedon Formation in the Exmouth Sub-Basin offshore Western Australia. Excellent quality 3D seismic has enabled attribute mapping and probabilistic seismic inversion to be used to both estimate the net sand distribution of the reservoir and facilitate optimal well placement. The reservoir comprises excellent quality, but poorly consolidated, sand rich turbidites up to 20m thick. The field lies in >800m of water and has been developed with four near horizontal gravel packed production wells connected to an FPSO via sub sea trees and flowlines.
Water injection is required for pressure maintenance and produced gas is re-injected into the nearby Eskdale oil & gas field, the oil leg of which is produced via a single horizontal well. Pressure support is required from field start-up due to lack of aquifer support. Horizontal production wells with high productivity indices are required for optimal drainage. Downhole sand control is provided by a combination of open-hole gravel packs and sand screens.
Key subsurface challenges were faced in the development of the relatively thin reservoir containing biodegraded 22° API oil with little or no aquifer support. Lateral reservoir variations have important implications for connectivity and therefore the optimal drainage of such fields.
The Stybarrow project involves a nine well subsea development and a double hulled FPSO, the Stybarrow Venture, with capacity of approximately 80,000 barrels of oil a day. Oil came on stream in November 2007 and nameplate production was reached within weeks of first oil. The Stybarrow and Eskdale fields which make up the project have estimated recoverable oil reserves of 60 to 90 million barrels and estimated field life is 10 years.
This paper documents a multidisciplinary approach applied during the appraisal, development and early production life of the field. Static and dynamic data on a variety of scales (i.e. seismic, well data, bed boundary resistivity modeling, inter-well interference testing and early production performance) have been integrated into detailed 3D geological models, which have enabled a greater understanding of reservoir connectivity, as well as a better estimation of ultimate oil recovery.
The Stybarrow oilfield is located in Production License WA-32-L, some 56km northwest of Exmouth, offshore Western Australia (Figure 1). Water depth over the field is approximately 825m. The field lies near the southern margin of the Exmouth sub-basin within the overall Carnarvon Basin. Although the potential of the Stybarrow structure had been recognised on 2D seismic data, it was not high graded for drilling until seismic amplitude anomalies conforming approximately to structure were observed in a subsequent 3D seismic dataset acquired in 2000. The 3D seismic data indicated the prospect had many similarities to the nearby Laverda and Enfield discoveries.
Biodegraded (22° API) oil is trapped in Early Cretaceous, Berriasian age turbidite and debris flow sandstones deposited on a passive margin slope. The Stybarrow structure comprises a NE-SW trending tilted fault block forming a terrace within the westward plunging Ningaloo Arch (Figure 2a). The intersection of NNE/NE and E-W trending normal faults establish an elongate, triangular trap with dip closure to the east and structure dip of about 5 degrees. Top, base and bounding-fault seals are provided by claystones and siltstones of the overlying Muiron Member of the Barrow Group and mudstones of the underlying Dupuy Formation. Oil is sourced from claystones of the Dingo Formation.
The Stybarrow Oil Field is located in Block WA-255-P offshore Western Australia, in an average water depth of 800m. This paper is a work-in-progress case-study of the process of discovery and appraisal of the Stybarrow field, and the influence on appraisal and development decisions of integrating the various types of geological, geophysical, and engineering data and techniques available to the modern oil company and their partners.
In the fault bounded Stybarrow structure, medium viscosity, medium GOR oil is reservoired in high quality but friable sandstones of the Lower Cretaceous Macedon Member. The average reservoir depth is around 2200mSS. High quality 3D seismic data has been used to both significantly reduce uncertainty in modelling the Stybarrow structure, and attempt to predict reservoir quality and distribution using well-calibrated seismic inversion to relative acoustic impedance. Results from the use of seismic inversion have been fundamental in constructing static reservoir models. The static geological modelling has been used in the construction of simulation models, with the view to simulating flow of the near-saturated oil through the relatively thin Macedon reservoir and thus predicting production. Pre-project feasibility simulation results were used to select a preferred reservoir management scheme. A simulation derived Integrated Production Model was then constructed. This allowed examination of the interaction of reservoir with a proposed processing and facilities under given processing facility design constraints.
The influence of a number of data types on appraisal decision making and development planning is discussed. Elaboration is also made on the impact of near-field exploration potential, and the possible influence of this potential on Stybarrow development planning is also discussed.
Key Words: integration, geological modelling, seismic inversion, simulation, production engineering, exploration, appraisal, development planning, infrastructure.