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.
Africa (Sub-Sahara) A drillstem test was performed on the Zafarani-2 well--located about 80 km offshore southern Tanzania. Two separate intervals were tested, and the well flowed at a maximum of 66 MMscf/D of gas. Statoil (65%) is the operator, on behalf of Tanzania Petroleum Development Corporation, with partner ExxonMobil Exploration and Production Tanzania (35%). The FA-1 well--located in 600 m of water in the Foum Assaka license area offshore Morocco--was spudded. The well targets Eagle prospect Lower Cretaceous resources. Target depth is 4000 m. Kosmos Energy (29.9%) is the operator, with partners BP (26.4%),
Africa (Sub-Sahara) Eni started production from the Nené Marine field, which sits in the Marine XII block in 28 m of water, 17 km offshore the Republic of the Congo. The first phase of the field produces from the Djeno pre-salt formation, 2.5 km below the ocean floor at a rate of 7,500 BOEPD. Future development will take place in several stages and will involve the installation of more production platforms and the drilling of at least 30 wells. Eni (65%) is the operator with partners New Age (25%), and Société Nationale des Pétroles du Congo (10%). The well's primary target is the Bunian structure: a four-way, fault-bounded anticline, which was defined by a 3D seismic survey. It will be drilled to a total depth of 1682 m.
The negative impacts of high water cut in mature fields are well known within the oil & gas industry. Water production preventive & mitigative measures are well established and documented: Wireline or coil tubing conveyed diagnostic and work-over operation(s) is one of such common preventive measures. This paper, through a series of integrated case studies will highlight the best practices for wireline conveyed logging and work-overs with one common goal, i.e. to achieve the water production to a minimum acceptable level in deviated high water cut wells.
The prolific XYZ field is located in the Northern North Sea and it produces oil from Jurassic Brent Group. Oil production from the XYZ reservoir started in early 1978, with 43 producing wells and 15 water injection wells targeting the Rannoch, Etive, Ness and Tarbert sands. Oil and gas production peaked in 1982 and since then production has steadily declined for this field. The increasing water cut in the wells of this field is presenting a challenge for the operating companies.
Production profiling using advanced Production Logging data, casing/tubing integrity check using Multi-Finger Caliper data and saturation monitoring using cased-hole Reservoir Saturation data was done in these wells to ascertain the water producing zones and do the subsequent well intervention, if required. A strategic diagnostic test was designed to precisely evaluate the flow profile using advance production logging tool consisting of 5 mini-spinners & 6 sets of each electrical and optical probes; Real-time data assessment and analysis was done for different flowing rate surveys to validate the findings. Additionally, casing condition was evaluated using Multi-Finger Caliper to decide Plug or Straddle setting depths. Also, new hydrocarbon bearing zones were identified based on cased-hole saturation tool results. The analysis results boosted the cumulative oil production.
This study demonstrates the importance of making real time interpretation decisions at the wellsite and the benefit of developing a good working relationship between wellsite engineers and onshore technical support. The results of this work led to the unequivocal determination of major oil and water producing zones in deviated high water cut (95%+) wellbores which further helped in taking workover decisions to carry out water shut off, utilizing either plug or straddle technology. The findings of caliper data determined the appropriate plug or straddle setting depths. The results were compared and confirmed with the nearby well dynamic pressures and production data.
The technical approach and processes applied to wells of XYZ field is a valuable example guide to decide water shut off zones and technique of similar plays. This study consists of three integrated case studies from a mature field where water shut-off zones and technologies were decided based on the findings of production logging and well integrity data. Also, re-perforation jobs were performed based on the cased-hole reservoir saturation data results. These strategic workover operations ultimately led to significant increase in hydrocarbon production.
On the Vega gas condensate and oil field in the Norwegian North Sea, two high temperature, high pressure (HTHP) gas condensate wells on one subsea template in 370 m water depth were acid and scale inhibitor treated in order to improve productivity by acid scale removal and prevent future scaling. Significant amount of work was undertaken on design and qualification of the treatment fluids. In order to reduce operation time and increase efficiency, a novel one-time connection concept was utilized. During the operations, wells were kicked off after energizing with gas bullheaded from the neighbouring well. The treatment fluids were designed to reduce consequences for the host facility due to H2S generated during the operation - this required optimization after understanding of the H2S source as witnessed in prior treatments.
The new concept with one-time connection was successfully employed and allowed for three subsequent well treatments in a row, thus saving at least two days vessel operations time. The gas injection from the neighbouring well - the one not treated at the moment - allowed for an efficient start-up of the treated well without need for larger nitrogen injection which would have led to contamination and potentially to flaring due to off-spec gas. The introduction of a batch with pH neutralizer and H2S scavenger batch into the treatment design to be placed into the production pipeline reduced H2S liberation and production to the host facilities, thus limiting the operational stress on the platform. Productivity of well A1 showed an immediately significant increase after the operations, whereas productivity of well A2 required a longer clean-up than originally anticipated.
Water-alternating-gas (WAG) injection is a technique employed in EOR (Enhanced Oil recovery). WAG injection can be immiscible or immiscible with water and gas being injected into the hydrocarbon liquids reservoir to promote greater recovery. WAG injection is effective as gas typically has greater microscopic sweep efficiency whilst water has better macroscopic sweep efficiency. It is important to be able to characterise and quantify how much the degree and type of small/medium scale heterogeneity during WAG flooding could affect the recovery factor from a reservoir, such that during project evaluation teams are able to properly evaluate the ranges on uncertainty on recovery factors and the economic benefit of the project as well as risks associated with WAG implementation.
The Hutton field is located in the North Viking Graben area of the North Sea and the lithology of the reservoir section is made up of Brent group sandstones which are highly heterogeneous in the horizontal and vertical directions at a small scale (i.e. pore scale and plug scale) and at a medium scale (the vertical layering of different formations).
The effect of reservoir heterogeneity on WAG efficiency has been evaluated using dynamic reservoir simulation models of the Hutton field. Input parameters were based on an available model of the Hutton Field. A fine grid geological model (grid size 5ft × 5ft × ~2ft) has been created of a small section of the Hutton reservoir. A variety of field development schemes were evaluated including depletion, water injection, gas injection and immiscible WAG production scenarios. Geological models were created for three scales of heterogeneity (small scale and medium scale heterogeneity models, and a homogeneous model) based on interpretation of log data from a set of three control wells. Compositional simulation models were used to model the dynamic behaviour. Two phase relative permeability (oil / water and gas / oil) data was used, as three phase relative permeability data for Hutton was not available. There is no hysteresis data available for the Hutton field, therefore separate test runs were carried out to evaluate how hysteresis might affect recovery factor during WAG injection using two and three phase relative permeability data and parameters for use in the Killough correlation for hysteresis.
Immiscible WAG injection is beneficial in reservoirs with small and medium scale heterogeneity and gives ~5% improvement in recovery factor when compared to water injection. However, when hysteresis is included, the recovery factor may be higher than this by another ~10%. WAG injection may provide inferior recovery factors to water injection in homogeneous reservoirs. However, simulations indicated that some limited gas injection into a homogeneous reservoir may prove beneficial for accessing attic oil. It is recommended that laboratory testing of core samples (core flood experiments) be carried out prior to a WAG injection specifically with the aim of identifying the most appropriate hysteresis model and to give good relative permeability data across all three phases.
The existing literature provides little guidance on the relevance of formation damage or return permeability results obtained from reservoir-conditions core flood testing on sandstone cores with heavy formate fluids. The drilling and completion in open hole of all six production wells in the Huldra field with heavy formate fluid provided a rare opportunity to appraise the results from HPHT core flood testing carried out on Ness (North Sea Brent Group) sandstone reservoir cores as part of the original drilling fluid qualification process for the Huldra development program.
Low- and high-permeability sandstone core plugs obtained from the productive Ness reservoir formation in the Huldra field were subjected to static and dynamic exposure to heavy formate drill-in fluids under HPHT reservoir conditions at 350 psi overbalance for a period of 296 hours. The cores were then exposed to short-duration drawdowns under HPHT reservoir conditions to simulate the very early phase of production start-up. The permeability impairment results obtained in these laboratory tests were compared against the production performance data for six Huldra field wells drilled and completed with sand screens in open hole in Brent Group sandstones with the same heavy formate fluids.
The reservoir-conditions (11,400 psi, 150°C) core flooding test with a SG 1.92 formate drill-in fluid sample from a Huldra well drilling job reduced the permeability of a 1416 mD Ness core by 37.8%. The same fluid reduced the permeability of a 2.8 mD Ness core by 65.9%. Repeating the same reservoir-conditions core flooding tests with a fresh SG 1.92 formate drill-in fluid sample prepared in the laboratory gave very similar results. In all cases the permeability of the cores was restored to original levels by soaking the wellbore face of the cores at balance for 24 hours with 15% acetic acid under reservoir conditions. The full restoration of permeability by non-invasive soaking of the core faces with dilute organic acid at balance suggested that the source of the tractable impairment was residual CaCO3/polymer filter cake still pressed onto the core face after lengthy drilling fluid exposure at overbalance and a very short clean up by drawdown.
The six Huldra production wells were drilled with SG 1.92 formate fluid at 37°-54° inclinations through the Tarbert, Ness, Etive and Rannoch reservoir formations and completed in open hole with 300-micron single-wire-wrapped screens. The wells cleaned up naturally during production start-up, without the need for acid treatment, resulting in skins that were at the low end of the expected range. The Hudra field was shut down in 2014 after producing 17.3 GSm3 of gas, representing an 80% recovery of the original gas in place.
This has been a useful first appraisal of a set of historical return permeability test results obtained with heavy K/Cs formate fluids. As more data become available from other HPHT gas condensate fields developed entirely with heavy formate brines (e.g. the Kvitebjørn and Martin Linge fields) it may become possible to assign some predictive value to the results of return permeability tests with these fluids.
Vucelic, Lara Antonia Blazevic (Norwegian University of Science and Technology (NTNU)) | Duffaut, Kenneth (Norwegian University of Science and Technology (NTNU)) | Avseth, Per (Norwegian University of Science and Technology (NTNU))
These processes are affected by rock microstructure, pressure regimes and temperature history. Data from 30 wells have been used to investigate and compare the changes in porosity, bulk density, elastic moduli and wave propagation velocities between mid-Jurassic sandstones in the North Sea and the Norwegian Sea. Mechanical compaction and quartz cementation models are used together with rock physics diagnostics to describe these changes. Introduction The physical properties of rocks are fundamental for the study of sedimentary basins and the characterization of hydrocarbon reservoirs. Properties such as porosity, bulk density and wave propagation velocities of the rock can be obtained or derived from well log data and they may provide information about rock composition and structure.
Hussain, Sajjad (Schlumberger) | Dhaher, Karam Sulaiman (Schlumberger) | Bjoerneli, Hans Magnus (Schlumberger) | Blackburn, Jason (Schlumberger) | Monterrosa, Leida (Schlumberger) | Jakobsen, Tom (Statoil ASA) | Otto Monsen, Gisle (Statoil ASA) | Haaland, Sigurd (Statoil ASA) | Dahl, Johan (Statoil ASA) | Østensen, Ståle (Statoil ASA) | Fjelde, Kjell Kåre (University of Stavanger)
AbstractOld platforms are not well known for extended-reach drilling (ERD) operations mainly due to rig and hydraulics limitations. ERD wells demand robust rig capabilities, good hydraulics systems, and equipment reliability. In addition, the well profile, rotary steerable system (RSS), measurement-while-drilling (MWD) and logging-while-drilling (LWD) tools, surveying, and new technologies are extremely important to the success in drilling an ERD well. RSS and drillpipe selection are important factors for hydraulics optimization. Surveying techniques are also important for time saving and improved efficiency. An ERD well in the North Sea Statfjord field was kicked off in the 17 ½-in. section from the openhole cement plug through a 50-m window between the 20-in. casing shoe and 13 3/8-in. casing stump, ensuring a smooth well profile and reduced doglegs compared to the whipstock window exit. The 17 ½-in. section was drilled and landed at a 79° inclination using point-the-bit RSS technology, and the 12 ¼-in. section was drilled in two runs as planned using the point-the-bit RSS withstanding more than 550 h down hole. The 9 5/8-in. liner was run and floated successfully in the ~6000-m section. Strict adherence to surveying techniques and quality control processes proved very helpful to meet Operator technical requirements. The 8 ½-in. section was drilled and landed on top of the reservoir with an inclination decrease from 88° to 35°. New MWD technology was successfully used in drilling the 6-in. section. These latest technologies as well as employing appropriate techniques help to drill ERD wells on aged platforms like those in the Statfjord field. This paper will describe the planning and execution phases of a challenging ERD well drilled in the Statfjord field.
When geological uncertainty is considered in production optimization problem, robust optimization on a set of plausible reservoir models is essential. We consider biobjective optimization where the two objectives are to find the optimal trajectories and/or control settings of injectors and producers that maximize the expected value of the life-cycle net-present-value (NPV) and minimize the risk where the risk is defined as the minimum NPV achieved for any realization. We consider cases where the vector of design (optimization) variables includes either well trajectories or well controls or both sets of variables. The trajectory of each well is parametrized in terms of the (