Alusta, Gamal Abdalla (Heriot-Watt University) | Mackay, Eric James (Heriot-Watt University) | Collins, Ian Ralph (BP Exploration) | Fennema, Julian (Heriot-Watt University) | Armih, Khari (Heriot-Watt University)
This study has focused on the development of a method to test the economic viability of Enhanced Oil Recovery (EOR) versus infill well drilling where the challenge is to compare polymer flooding scenarios with infill well drilling scenarios, not just based on incremental recovery, but on Net Present Value as well.
In a previous publication (Alusta et al., 2011, SPE143300) the method was developed to address polymer flooding, but it can be modified to suit any other EOR methods. The method has been applied to a synthetic scenario with constant economic parameters, which has demonstrated the impact that oil price can have on the decision making process.
The method was then applied and tested (Alusta et al., 2012, SPE150454) with varied operational and economic parameters to investigate the impact in delaying the start of polymer flooding to identify whether it is better to start polymer flooding earlier or later in the life of the project. Consideration was also given to the optimum polymer concentration, and the impact that factors such as oil price and polymer cost have on this decision. Due to the large number of combined reservoir engineering and economic scenarios, Monte Carlo Simulation and advanced analysis of large data sets and the resulting probability distributions had to be developed.
In this paper the methodology is applied to an offshore field where the choice has already been made to drill infill wells, but where we test the robustness of the method against a conventional decision making process for which there is historical data. We do this by performing calculations that compare the infill well scenario chosen with a range of polymer flooding scenarios that could have been selected instead, to identify whether or not the choice to drill infill wells was indeed the optimum choice from an economic perspective.
We conclude from all the reservoir simulations and subsequent economic calculations that the decision to drill infill wells was indeed the optimum choice from an economic perspective.
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 prospect of large oil and gas reserves in fields below Arctic waters hasdriven the design development of production solutions for these areas. Thispaper presents the development of an Arctic Turret Mooring System technologywhich facilitates year-round station keeping of floating offshore structures,like FPSOs in the Arctic environment. The Arctic turret mooring system candisconnect the mooring when the FPSO encounters extreme ice loads, which couldotherwise damage its hull or mooring system. When disconnected, a mooring riserbuoy supports the production risers and control umbilicals. The system isdesigned to quickly disconnect and re-connect the mooring riser buoy.Especially the fast re-connection will reduce the downtime to the productionsystem when disconnection is necessary.
The Bluewater Arctic Turret is based on further development of existingBluewater know-how and designs of (quick) disconnectable Turret MooringSystems. However, in addition to existing designs, the Bluewater Arctic Turretuses a unique and patented design that allows the mooring riser buoy to bereleased from the turret, while being subject to the large (horizontal) mooringloads. In this design, the mooring riser buoy is released from the turret tosink below the FPSO hull, before the mooring system is disconnected from theturret. Following disconnection, the mooring riser buoy descends further to asafe equilibrium depth away from ice hazards. This allows the disconnected FPSOto sail from its production location and later return for reconnection andquickly resume production. The paper presents the unique Bluewater ArcticTurret Mooring concept, its design basis, the development process as well asconsideration to key aspects such as operational and safety issues.
Brodie, James Andrew (BP Exploration) | Zhang, Pinggang (BP Exploration Operating Co) | Mellemstrand Hetland, Sigrun (BP Exploration Operating Company Ltd) | Moulds, Timothy Peter (BP plc) | Jhaveri, Bharat S. (BP Exploration (Alaska) Inc.)
BP has been operating gas injection projects in a variety of challenging environments throughout the world for more than three decades. Numerous innovative techniques have been used to optimize oil recovery and the results have been reported in a series of publications.
The focus of this paper is the North Sea, where BP operates offshore miscible gas floods in the Magnus and Ula fields and an immiscible gas flood in the Harding field. Tertiary miscible WAG in Magnus began in 2002 and its impact on reservoir performance is significant and well understood. More than 112 Bscf of gas have been injected into three mature panels, yielding 11.5 mmstb of oil at a very high net efficiency of 3.5 mscf/stb. The contribution of EOR to total field production has increased to 40% by 2010. In Ula, tertiary miscible WAG started in 1998 and has played a key role in arresting production decline. More than 23 mmstb of oil has been recovered by gas injection, which accounted for 60 - 70% of total field production in 2010. Key to the success of both projects has been securing a source of miscible gas and pursuing an active surveillance and reservoir management programme to monitor and optimize the flood.
The success of the North Sea projects is partly based on the experience of operating the world's largest miscible gas flood at Prudhoe Bay (Alaska), where conventional and unconventional techniques have been successfully applied in a variety of different settings. The knowledge acquired in Prudhoe Bay has been shared with other assets, including the North Sea, through a series of managed moves and master classes.
Miscible gas injection has generated considerable benefits for BP over the past three decades and will continue to do so in the future. The potential availability of large sources of CO2 in the future, through carbon capture, could help maintain a leading role for miscible gas injection for years to come.
North Sea gas floods
BP operates three large-scale offshore gas injection projects in the North Sea, namely the miscible gas projects in the Magnus and Ula fields and the immiscible produced-gas re-injection project in Harding field.
The Magnus field is located in the northern North Sea (see Figure 1). Magnus is operated by BP (85% equity) and is coowned by JX Nippon Exploration & Production (U.K.) Limited (7.5%), Eni (U.K.) Ltd (5%) and Marubeni North Sea Ltd
(2.5%). The field was initially developed by peripheral water-flooding. First oil was produced in 1983 and plateau production (150 mstb/D) was maintained until 1995, when sea water broke through at the crestal wells and severe barium sulfate scaling problems were encountered (see Figure 2).
In many oil fields water production often threatens the reservoir performance and economic viability of wells. Excess unwanted water production can cause an increase in production costs and a decrease in productivity. To mitigate this, it is crucial to utilize water management techniques to reduce water cut (WC), optimize oil production, extend the well life and recover idle wells.
The most effective technique for water shut off (WSO) treatments in Saudi Arabia comparatively to the costly workover rig treatments was proved to be a rigless WSO using mechanical isolation especially when it gives options to perform additional operations with the single rigup.
This paper describes the first time — in Saudi Arabia — implementation of the mechanical rigless WSO method, used to mechanically isolate a watered open hole section. This isolation is accomplished by utilizing fiber optic enabled coiled tubing (FOECT) telemetry and then setting an inflatable packer in the liner. It is capped with cement following perforation treatment, by using a completion insertion and retrieval under pressure (CIRP) deployment system, which allowed the guns to be run and pulled under live well conditions without killing the well.
The depth correlation for the packer setting — and later for perforation depth correlation — was performed by fiber optic bottom-hole assembly (FOBHA-GR). The inflation of the packer and the injection through it were monitored and adjusted realtime with the FOBHA-Pressure - Temperature - Casing Collar Locator (FOBHA-PTC) measurement inside and outside the FOCT string. FOBHA utilize deployment method from CIRP technology to perforate the new formation by using the TCP E-Fire firing head under well dynamic underbalanced conditions.
Recent production results showed a previously dead well flowed at 10 thousand barrels per day oil rate with 12% water cut.
This innovative combination of WSO solution with FOECT and CIRP techniques proved to be an effective method to minimize operational time, equipment and footprint on location, and efficient perforating in a single underbalance run at one rigup.
This paper also discusses the challenges faced during job execution, lessons learned, and experience gained to optimize similar jobs in the future.
This study presents examples of fields operated by Total where are observed incompatibilities between reservoir formation water and injected seawater. In these examples, we show the scatter between risk estimated by modeling and site observations.
The prediction of calcium sulfate deposits identified by modeling is not valid as the scaling problems are either non-existent or considerably less serious than expected. With respect to the precipitation of barium sulfate, the risk estimated by modeling is always much higher than reality. In this study information are provided that will allow us to have more realistic scaling predictions in the future.
In many oilfields the relatively small number of high-cost, highly productive wells, coupled with a carbonate and or sulfate scaling tendency (upon waterflood breakthrough of injected seawater) requires effective scale management along with removal of near-wellbore damage in order to achieve high hydrocarbon recovery.
The nature of the well completion strategy in new fields such as frac packs for sand control and acid stimulation for carbonate reservoirs had resulted in some wells with higher than expected skin values due to drilling fluid losses, residual frac gel, fluid loss agents, and fines mobilization within the frac packs where applied.
The paper will present how the challenges of managing impaired completions and inorganic scale forced innovation in terms of when to apply both stimulation and scale inhibitor packages to sandstone and carbonate reservoirs. This paper will outline a novel process for non-conventional batch chemical applications where bullhead stimulation treatments have been displaced deep into the formation (>20ft) using a scale inhibitor overflush. Not only does this benefit the stimulation by displacing the spent acid and reagents away from the immediate wellbore area, but the combined treatment provides cost savings with a single mobilization for the combined treatment. The paper will describe the laboratory testing that was performed to qualify the treatments for both sandstone and an HP/HT gas condensate carbonate reservoir. The lessons learned fromcarbonate corefloodevaluationunder HT/HP conditions when appling stimulation fluids with and without scale inhibitor present in the treatment stageswill be presented.
Many similar fields are currently being developed in offshore Brazil, West Africa and Middle East, and this paper is a good example of best-practice sharing from another oil basin.