Recently two multilateral horizontal wells have been completed offshore using dedicated multistage hydraulic fracturing completions. The first well, located in the Central North Sea (referred to as ML-CNS), was stimulated using acid fracturing; while the second well, located in the Black Sea (referred to as ML-BKS), was stimulated using proppant fracturing. This paper presents the different drivers, challenges and lessons learned for each well while emphasizing the well construction and stimulation methodologies developed for the different reservoirs and field characteristics.
The field development drivers for drilling and completing these offshore hydraulic fractured multilateral wells, a first of their kind globally, was different for each case. The objective of the first project, initially considered uneconomic, was to engineer a technical solution for completion and production of two separate reservoirs with only one subsea well. The second project was seeking to optimize infill drilling from the last available slot on the offshore platform to maximize reservoir contact and production in the same reservoir. ML-CNS was a TAML Level 2 completion with a 14-stage, 5 ½" multistage completion run in each lateral and set-up for sequential acid fracturing. Operationally, the first lateral was drilled and stimulated, followed by the drilling and stimulation of the second lateral, using the drilling whipstock to navigate through the multilateral junction. ML-BKS was a TAML Level 3 completion that had a 6-stage, 4 ½" multistage completion installed in each lateral, which were proppant fractured following a sequence designed to minimize the jack-up rig time required. Both legs were drilled and completed prior to starting the stimulation, access to either lateral was achieved with the existing workover unit on the platform by manipulating a custom designed BHA.
The lessons learned from the first project executed in the North Sea were able to be transferred and applied to the second project in the Black Sea to allow for a more efficient and confident completion solution. Led by varying economical and regional constraints, the key factor for both wells centered on delivering operationally simple and reliable multilateral completion designs to economically meet the field development strategy in place.
To the knowledge of the authors and following subsequent literature research, both wells are a worldwide first for an offshore multilateral well completed with multistage acid fracturing and multistage proppant fracturing, and together they represent a new trend in cost-effective offshore field development through well stimulation. The successful case studies for both wells with the combined analysis of the benefits, challenges, and lessons learned will provide a guide and instill confidence with operators who find this approach beneficial with a view to applying it in other assets.
Following the significant reservoir depletion on Elgin / Franklin fields since 2007, drilling infill wells was considered to not only be high cost but also carry a high probability of failure to reach the well objective. The recent campaign on the Elgin field, one of the most heavily depleted reservoirs worldwide, demonstrated that infill drilling can be achieved safely while improving performance.
Drilling of HPHT infill wells on the Elgin field faced increasing challenges arising from the reduction of reservoir pressure that changed the stresses in the formations above and influenced the overall pressure regime. This stress reorganization in the overburden has affected the fracture network in these formations resulting in reduction in Fracture Initiation Pressure (FIP) and increase of gas levels.
Challenges were faced during the drilling of three wells in the 2015-2017 campaign. Loss events in Chalk formations in the intermediate sections significantly decreased the already Narrow Mud Weight Window (NMWW). A strategy to define and validate the minimum required MWW in 12-1/2" and 8-1/2" sections was developed following a complex subsurface well control event. Managed Pressure Drilling (MPD) technique was extensively used to safely manage gas levels and assess pore pressure.
Reservoir entry with more than 850 bar of overbalance remains the main challenge in infill drilling. A total loss event during first reservoir entry in the latest campaign confirmed the limitations of wellbore strengthening mud and stress caging materials available today.
Lessons learned from each well in this campaign were implemented to address these challenges and improve performance. This paper describes the Elgin HP/HT infill drilling experience and the specific techniques and practices that were developed to address these challenges and improve performance. The importance of Equivalent Circulating Density (ECD) management with very narrow MWW, successful high gas level management with MPD and depleted reservoir entry, shows that even in a highly complex environment, drilling performance can be improved allowing for further economical development drilling. The successful and safe delivery of the Elgin 2015-2017 infill drilling campaign demonstrates this at a time the industry moves toward unlocking the reserves of more challenging HPHT fields.
Saasen, Arild (University of Stavanger) | Pallin, Jan Egil (JAGTECH AS) | Ånesbug, Geir Olav (JAGTECH AS) | Lindgren, Alf Magne (Schlumberger Oilfield Services) | Aaker, Gudmund (Schlumberger Oilfield Services) | Rødsjø, Mads (AkerBP)
Different logging operations can suffer from presence of metallic particles in the drilling fluids. Directional drilling in Arctic areas can be a challenge because of magnetic contamination in the drilling fluid. This is a challenge especially when drilling east-west relative to the magnetic north direction. Magnetic and paramagnetic particles in the drilling fluid will shield the down hole compasses and introduce additional errors to the surveying than those normally included in the uncertainty ellipsoid. The objective of the project is to remove the magnetic particles being the largest contributor to this error.
On many offshore drilling rigs there is mounted ditch magnets to remove metallic swarf from the drilling fluid. These magnets will normally only remove the coarser swarf. In this project we use a combination of strong magnets and flow directors to significantly improve the performance of the ditch magnets. This combination, together with proper routines for cleaning the ditch magnets significantly helps cleaning the drilling fluid.
By the combined use of flow directors and ditch magnets it was possible to extract more than five times as much magnetic contamination from the drilling fluid. This is verified by comparing the ditch magnet efficiencies from two drilling rigs drilling ERD wells. The logging tool signal strengths of several down hole instruments were unusually good and insignificant down times were observed on the logging tools. The results are anticipated to have aided to the directional drilling performance.
Detailed information on how to clean the drilling fluid properly from magnetic contamination is presented. It is also shown that this cleaning is significantly better than conventional cleaning of magnetic debris from drilling fluids.
Tyrie, Jeb (Bridge Petroleum) | Mulcahy, Matt (Bridge Petroleum) | Leask, Robbie (Bridge Petroleum) | Wahid, Fazrie (Bridge Petroleum) | Arogundade, Olamide (Schlumberger) | Khattak, Iftikhar (Schlumberger) | Apena, Gani (Schlumberger) | Samy, Mohammed (Schlumberger) | Sagar, Rajiv (Schlumberger) | Xia, Tianxiang (TRACS International) | Nyadu, Kofi (WorleyParsons, Advision) | Maizeret, Pierre-David (Schlumberger)
This paper describes the proposed re-development of the Galapagos Field, comprising the abandoned NW Hutton field and the Darwin discovery (Block 211/27 UKCS) which forms a southerly extension. The paper covers the initial concept and analytical evaluation, the static uncertainty model build, the dynamic model history-match, the iterations between static and dynamic modelling, the development subsea and well locations, the optimisation workflow of the advanced Flow Control Valve (FCV) completions in both producers and injectors and the facilities constraints.
The redevelopment plan involved several multi-disciplinary teams. 20 years of production data from 52 wells were analysed to identify the production behaviour and confirm the significant target that provided the basis for the development concept selection. The full Brent sequence compartmentalised stochastic static model was based on reprocessed seismic plus 14 exploration and appraisal wells. Streamlines, uncertainty sensitivities and mostly good detective work honed a history match to RFT, BHP, PLT and oil and water production. P50, P90/P10 models were selected and over 100 FCVs optimised to deliver the profiles against an identified FSPO facilities’ constraints.
Over 1,000 static models were delivered consisting of sheet sands, incised valleys and channels in heterolithic facies overprinted by a depth trend with appropriate uncertainty ranges. The high well count gave a tight STOIIP probabilistic range of 790/883/937 million stb. The early RFTs illustrated extreme differential depletion between Brent zones and subzones of the Ness. To history-match these the dynamic model retained the static model definition in the Upper Ness to capture the thin but extensive shales. The early 18-month depletion and the late steady production-injection phases were simulated separately in prediction mode and matched the Production Analysis estimated ‘future’ production giving confidence to the history matched model. The initial concept development of 4 subsea-centres, to cover the large field area, with an injector in each compartment proved a robust selection. The horizontal wells increase PI where needed and mitigate internal faulting. The optimisation of the FCVs significantly increased oil production from all zones and drastically reduced water injection and production so that the identified FPSO modifications were relatively modest. The final First Stage Field Development Plan consists of 11 producers and 6 injectors across developed and undeveloped areas confirmed robust P50 reserves of 84 million boe.
Robust concept selection allowed for early identification of production units so that constraints and modifications could be accounted for within the economic model.
The Galapagos field re-development plan is an excellent example of how detailed static and fully history matched dynamic models can lay the foundations for new technology like the optimisation of the FCVs to access bypassed reserves using significantly smaller production units with reduced requirements for power, compression, gas lift, pumping pressure, injection and production. In short, they shrank the facilities.
The Internet of Things (loT) has paved the way for significant efficiency gains in the oil and gas industry. One concept that has garnered significant attention is the "digital twin". However, there remains a great deal of confusion surrounding what a digital twin actually is and how it can be harnessed to add value to oil and gas operations. Some use digital twin as a synonym for their 3D plant models, others for their predictive maintenance solutions, or their simulation models. The bottom line is that the digital twin is all of these and more and unless operators look at it holistically, they are likely to miss out on some of the benefits.
Digital twins afford companies a number of advantages that would otherwise not be possible, including the ability to run risk analyses, health assessments, and what-if scenarios in real-time; the ability to train personnel in a 3D immersive, risk-free environment; and the capability to detect faults early before control limits are reached. This paper/ presentation will elaborate on how digital twins can be used to enhance efficiency and will address their use in the wider context of the oil and gas industry – with a particular focus on its impact on reducing risk and cost during both the project and operational phases of the asset lifecycle.
The objective is to demystify the digital twin, outline the advanced capabilities it enables and illustrate how oil and gas operators can use this concept to improve their competitive advantage.
The US is putting its offshore assets up for sale to compete for exploration dollars as offshore drilling begins to grow again. By creating a different sort of partnership for a drilling project with close cooperation and greater efficiency built into every detail, including the contracts, Statoil was able to halve the cost of drilling eight wells at its Johan Sverdrup field.
The technology will provide Equinor a continual feed of updated reservoir information from its Johan Castberg and Johan Sverdrup fields with the aim of improving well placement, production, injection, and—ultimately—recovery. Statoil has submitted a long-awaited development plan for what will become Norway’s northernmost development.
It will provide re ... Harkand has secured a USD 5 million contract from Swiber Offshore Mexico to perform saturation divin ... Two Bumi Armada subsidiary companies secured USD 300 million worth of contracts from ElectroGas for ... Amec Foster Wheeler has been awarded a contract by BP worth more than USD 73 million. Tam International, which provides inflatable and swellable packers for the oil and gas industry, has ... Sanchez Energy closed a deal with a subsidiary of Sanchez Production Partners to sell wellbore and a ... Penn West Petroleum has entered into a USD 321 million agreement with Freehold Royalties to sell an ... Bonterra Energy has acquired Cardium formation-focused assets in the Pembina area of Alberta, Canada ... Petrobras has sold its assets in Argentina’s Austral basin to Compañia General de Combustibles for U ... Pemex signed an agreement worth USD 1 billion with private equity firmFirst Reserve to jointly inves ... Gulfport Energy entered into an agreement to acquire Paloma Partners III for USD 300 million. Apache sold its 13% stake in the Wheatstone LNG terminal in Western Australia and 50% interest in th ... Shell Petroleum Development Company of Nigeria completed the sale of its 30% interest in Oil Mining ... Oil and gas safety company Secorp opened a new office in Hobbs, New Mexico. Bill Barrett Corp. has signed agreements with several undisclosed recipients for the sale of the maj ... Encana said it will sell its remaining 54% stake in PrairieSky Royalty via a USD-2.4-billion Cardinal Energy entered into an agreement with an unnamed seller to acquire assets whose total daily ... Petrobras has awarded a contract, worth USD 465 million over a period of 5 years, to Aker Oilfield S ... CGG received contracts for the 3D seismic acquisition of four surveys using its marine broadband tec ... IKM Subsea, a subsidiary of IKM Group, has been awarded a contract by Eni Indonesia to provide remot ... OneSubsea, Schlumberger, and Helix Energy Solutions signed a letter of intent to develop technologie ... Premier Hytemp has committed to opening a USD-20-million, 67,000-ft2 precision engineering facility ... Expro has constructed a new 20,000‑m2 facility in Macaé, Brazil.
Asia Pacific Santos discovered gas with the Corvus-2 well in the Carnarvon Basin, offshore Western Australia. The well, located in permit WA-45-R, in which Santos has a 100% interest, reached a total depth of 3998 m. It intersected a gross interval of 638 m, one of the largest columns discovered across the North West Shelf. Wireline logging to date has confirmed 245 m of net hydrocarbon pay across the target reservoirs. Total SA and partners ExxonMobil and Oil Search have signed a gas agreement with the government of Papua New Guinea that defines the fiscal framework for the Papua LNG project in the country's Eastern Highlands. The plan involves construction of three 2.7-mtpa LNG trains on the existing PNG-LNG plant site at Caution Bay just west of Port Moresby. Total has 31.1% interest, ExxonMobil has 28.3% interest, and Oil Search has 17.7%.