Latin America-Caribbean Petrobras and CNPC have signed a memorandum of understanding in Beijing to begin negotiations on a strategic partnership, Petrobras has reported. The companies agreed in the document to jointly evaluate opportunities in Brazil and abroad in key areas of mutual interest. Petrobras, the Brazilian national oil company, said in a news release on its website that partnerships will represent an important strategy in its 2017–2021 business plan because of the potential benefits of risk sharing, increasing investment capacity, technological exchange, and strengthening corporate governance. YPF, Total, Wintershall, and BP have announced a USD 1.15-billion joint investment to increase shale gas production in Argentina. The provincial government in Neuquén, where the resource-rich Vaca Muerta Shale is located, has agreed to split the Aguada Pichana area into two parts and combine it with the Aguada de Castro area.
Among the many goals of environmental management in Saudi Aramco, protection of special environmental areas is recognized as high priority to both the company and the Kingdom of Saudi Arabia. In line with this objective, Safaniya Onshore Producing Department (SONPD) designated Safaniya area sea water lagoon as Corporate Stewardship Biodiversity Area. The area is estimated to be 6 km2 peninsula, which is located in the north east of the Safaniya Producing Plant, where undisturbed native flora combines with a pristine shallow sea water lagoon, and provide a safe place for land wildlife (foxes, rodents, reptiles), marine wildlife (turtles, shrimps, fish, mollusks) and birds (flamingos, seagulls, etc.). Establishment of the Safaniya Lagoon started with surveying Safaniya and Tanajib Area, in collaboration with Saudi Aramco Environmental Protection Department (EPD) to select the most suitable region for biodiversity development. An establishment procedure was followed to secure the area with fences to limit the accessibility and prevent improper usage. A signboard was installed to identify the area as a sanctuary, forbidding entrance or any type of land use. Site development included mangrove plantation, already existing trash clean-up, and observation any type of waste dumped in the area, to ensure no contamination or danger to the habitat in the lagoon. The department successfully cooperated with Saudi Aramco EPD to plant more than 9,000 mangrove seedlings at the first two years of development. SONPD in collaboration with Society of Advocates and Volunteers for the Environment (S.A.V.E) invited employees with their respected family members to participate in a biodiversity beach clean-up campaign. The campaign helped collect more than 300 kg of waste, consisting of plastic bottles, old ropes, wood, and other waste materials. SONPD, along with its partners and programs, has now established the Safaniya Lagoon ecological and biological diversity sanctuary as a permanent refuge, with in-place protection and future mangrove planting events planned, the area is expected to expand in biodiversity with native flora and fauna, and expand a natural breeding and hatchery. During the winter season, migratory birds — such as flamingos and Amur Falcons, with flyways that pass over Safaniya Lagoon — are seeking warm weather and abundant food supplies. Creation of biodiversity is just the beginning of further area development. The next phase of sanctuary enhancement will be reutilization of tertiary treated wastewater for trees, which will form a wind barrier for mangroves.
Some of the first high-pressure/high-temperature (HP/HT) development wells from Elgin and Franklin have been exposed to sustained casing pressures in their "A" annulus, threatening the integrity of the wells. The sustained pressure in the annulus was attributed to ingress through the production casing of fluids from the overburden chalk formations of the Late Cretaceous. The mechanism triggering the ingress into the "A" annulus was uncertain until access to the production casing was achieved. A recent campaign to abandon development wells of Elgin and Franklin that had sustained "A"-annulus pressure brings new evidence on the mechanism causing the ingress. Temperature surveys have been acquired in the production tubing to identify the fluid-entry points in the production casing. Multifinger calipers have been run in the production casing, revealing several shear-deformation features. These deformations are localized along various interfaces, and are attributed to the stress reorganization associated with the strong reservoir depletion. A detailed analysis of the surveys shows that fluid ingress is occurring at distorted casing connections, if located close to weak interfaces along which shear slip occurs. The shear deformation is suspected to cause a loss of the sealing capacity of the connection, leading to gas ingress into the "A" annulus. This conclusion emphasizes the need to consider any potential for localized shear deformations in designing casing for HP/HT wells.
Low salinity waterflooding (LSWF), versus high salinity waterflooding (HSWF) has been the focus of significant research at various centres around the world, yet there is still considerable debate over the exact mechanism that provides incremental oil recovery. The use of the LSWF technique is not widespread in the United Kingdom continental shelf (UKCS). However, it has been announced that the Clair Ridge development will deploy low salinity waterflooding (LSWF) in secondary mode from the start of field life, and a number of companies are currently assessing the applicability of the technique through high level screening and core flooding. Forecasting the potential oil recovery under LSWF is heavily influenced by the simulation technique that is used. Presently the most widely discussed approach is the use of a weighting table with relative permeabilities representing the high and low salinity cases. As the grid block falls below threshold salinity, the simulator utilises the weighting table to assign an interpolated value of salinity. This value of salinity is utilised to represent a change in wettability. While this approach approximates the net effect of LSWF, it does not capture the oil/ rock/ brine interaction. This study examines the modelling approach to LSWF utilising an in-house generic Forties Palaeocene model in CMG’s STARS simulator. The conventional approach of modelling LSWF using high and low salinity relative permeabilities is compared to the latest Multi-component Ion Exchange (MIE) methods by numerical simulation to assess the impact on incremental oil recovery. A sensitivity analysis is then carried out on the effects of specific parameters on incremental oil recovery, utilising published data from fields in the Forties Palaeocene fan system. A discussion is provided. The impact on secondary recovery was accessed with respect to wettability alteration; injection salinity ( LSWF versus HSWF ); oil viscosity and aquifer influx. The application of LSWF in secondary mode to the Forties Palaeocene Sandstones was found to be favourable for the case of mixed-wet reservoirs.
Low salinity waterflooding (LSWF) is an enhanced oil recovery (EOR) technique which is of growing interest,as it represents a low cost and flexible form of EOR. The technique involves the injection of water at of a significantly lower salinity, compared to the natural salinity of the reservoir connate water. Until recently, although it was known that the ionic composition of a fluid flowing in a porous medium does influence the measured permeability ( Schleidegger 1974), the manipulation of this effect to improve oil recovery by injecting water of a different salinity and ionic composition to that of the natural formation water, had not been considered. As compared to the normal method of injecting seawater ( HSWF), LSWF is seen as a viable EOR technique. Further, LSWF offers the potential to increase recoverable oil without the need for re-engineering of the field, as it can use the existing infrastructure and wells, provided that facilities space exists topsides for installation of a reverse osmosis plant.
There is little commonality of fiscal incentives in the oil and gas sector. This is demonstrated in the North Sea, where rapidly changing market fundamentals had led to a range of fiscal measures aiming to incentivize the sector. Until very recently, rising cost of development against the backdrop of a maturing basin made the North Sea a less attractive place to invest in. Renewed interest in the North Sea seen in the last 5 years has been a direct result of the UK and Norwegian governments engaging with the stakeholders and introducing new policies which have the right incentives to extend basin life. However, in the UKCS, some would argue that these changes have come too late and investment and production levels have been already damaged. A brief review of the challenges in each country, the impact of fiscal incentives and to what extent they have been successful will form the main part of this paper.
Toal, Fred J. (Maersk Oil North Sea UK Ltd.) | Martin, John G. (Maersk Oil North Sea UK Ltd.) | Brown, Martin G. (GL Noble Denton Aberdeen) | Lindsay, Ian M. (GL Noble Denton Aberdeen) | Sinclair, Robert (GL Noble Denton Aberdeen)
In a North Sea storm during February 2011 the Gryphon Alpha FPSO broke four of her 10 mooring lines and moved partially off station, causing damage to subsea assets. Heading control was re-established using the FPSO's thrusters and in due course the moorings which had parted were re-connected back to the Tentech turret. Following the incident, the FPSO was taken to dry dock for life extension work and to allow replacement of the damaged subsea infrastructure and moorings. The original mooring system was recovered for forensic inspection.
This paper describes the measures which were put in place so that the Gryphon mooring system could be replaced and the FPSO re-connected in accordance with a schedule which would not delay the installation of the subsea infrastructure or first oil. The intention is that this paper should be a useful reference for others engaged in similar work. It was decided to replace the original moorings, apart from the recovered Stevpris anchors that were refurbished. Since the size of the chain into the gypsy wheel fairleads at the turret was fixed, the mooring designers had to optimise their design to meet latest code requirements. This resulted in a 100 m long tri-parallel chain configuration to reduce FPSO mooring loads and excursions, but which also caused some handling issues. High specification Anchor Handling Vessels (AHVs) were needed for the prelay operation, which had after deck chain handling gantries to manipulate safely the heavy chain, delta plates and associated shackles.
A challenging design and procurement exercise was needed to make sure that all the mooring components were delivered on time. The initial mooring sections were pre-laid in February/March of 2012, including anchor proof tensioning, so as to suit the subsea schedule. The mooring lengths had to be adjusted offshore by chain cutting, depending on the final resting place of the chain ends after tensioning. This was to ensure each tri-chain end was correctly located so that the system stiffness would be uniform and the moorings properly balanced. The pre-deployed mooring lines were each buoyed off subsea for later ROV recovery.
The FPSO moorings hook-up took place in September 2012 using the AHVs previously used for the pre-lay. Due to the presence of three Mid Water Arches (MWAs) within the FPSO swing circle, four AHVs were used to hold Gryphon in position during the reconnection operation. The AHVs were positioned two forward and two aft about the FPSO. Adjustment of AHV tow lines enabled the FPSO to be held within just 5 m of the Field Turret Centre (FTC) during the entire reconnection operation. The FPSO also had access to a 3D computation and visualization package which provided real time in-situ position monitoring. This ensured that no mooring chain to subsea assets contact occurred despite the unusually tight installation tolerances.
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.