Stavanger was home to the fourth annual Energy21 conference in March. Approximately 160 participants attended, including students, educators, contractors, young professionals, and senior employees from oil companies. This year, the participants could feel the optimism for the future of the oil and gas industry. The conference kicked off with an inspiring speech that brought the audience from the beginning of development on the Norwegian continental shelf (the Ekofisk field) to the challenges of the latest big development in the Ormen Lange field. With this background, the speakers drew a picture of future challenges in the oil and gas industry and the role the next generation, including students and young professionals in the audience, would have to play for this industry to succeed.
The young professional (YP) group of the SPE Netherlands Section is having a busy and exciting year. One of the biggest achievements of the section was the startup of two new student chapters at Utrecht University and VU University, Amsterdam. The increased input of students and the increasing numbers of YPs have boosted lectures and created a great atmosphere with excellent networking opportunities. The section organizes monthly lectures from companies active in the Netherlands for YPs and students. The topics covered this year, and their presenters, included the latest logging-while-drilling technologies, by Eric Shearer, Halliburton; the art of workovers, by Lex de Groot, GDF Suez; the upstream strategy of NUON, by Arnoud Kamerbeek, NUON; and the Bergermeer field, by Jan-Thijs de Keijser.
Taha, Taha (Emerson Automation Solutions) | Ward, Paul (Emerson Automation Solutions) | Peacock, Gavin (Emerson Automation Solutions) | Heritage, John (Emerson Automation Solutions) | Bordas, Rafel (Emerson Automation Solutions) | Aslam, Usman (Emerson Automation Solutions) | Walsh, Steve (Emerson Automation Solutions) | Hammersley, Richard (Emerson Automation Solutions) | Gringarten, Emmanuel (Emerson Automation Solutions)
This paper presents a case study in 4D seismic history matching using an automated, ensemble-based workflow that tightly integrates the static and dynamic domains. Subsurface uncertainties, captured at every stage of the interpretative and modelling process, are used as inputs within a repeatable workflow. By adjusting these inputs, an ensemble of models is created, and their likelihoods constrained by observations within an iterative loop. The result is multiple realizations of calibrated models that are consistent with the underlying geology, the observed production data, the seismic signature of the reservoir and its fluids. It is effectively a digital twin of the reservoir with an improved predictive ability that provides a realistic assessment of uncertainty associated with production forecasts.
The example used in this study is a synthetic 3D model mimicking a real North Sea field. Data assimilation is conducted using an Ensemble Smoother with multiple data assimilations (ES-MDA). This paper has a significant focus on seismic data, with the corresponding result vector generated via a petro-elastic model. 4D seismic data proves to be a key additional source of measurement data with a unique volumetric distribution creating a coherent predictive model. This allows recovery of the underlying geological features and more accurately models the uncertainty in predicted production than was possible by matching production data alone.
A significant advantage of this approach is the ability to utilize simultaneously multiple types of measurement data including production, RFT, PLT and 4D seismic. Newly acquired observations can be rapidly accommodated which is often critical as the value of most interventions is reduced by delay.
Gas injection is a proven EOR method in the oil industry with many well-documented successful field applications spanning a period of more than five decades. The injected gas composition varies between projects, but is typically hydrocarbon gas, sometimes enriched with intermediate components to ensure miscibility, or carbon dioxide in regions such as the Permian Basin, where supply is available at an attractive price.
Miscible nitrogen injection into oil reservoirs, on the other hand, is a relatively uncommon EOR technique because nitrogen often requires a prohibitively high pressure to reach miscibility. Unlike other injection gases, the minimum miscibility pressure for nitrogen decreases with increasing temperature. In fact, in deep, hot reservoirs containing volatile oil, nitrogen may develop miscibility at a pressure similar to the MMP for hydrocarbon gas or carbon dioxide. The phase behavior is more complicated than what can be captured by correlations and hence requires equation-of-state calculations.
Results from a recent EOR screening study in ADNOC indicate that a couple of high-temperature oil reservoirs in Abu Dhabi may be potential targets for miscible nitrogen injection. This paper discusses key aspects of the EOS modeling. Advanced gas injection PVT data are available to enable a fair comparison between nitrogen, carbon dioxide and lean hydrocarbon gas. In this work, we have modelled and analyzed the phase behavior of two volatile oil systems with respect to nitrogen, hydrocarbon gas, and carbon dioxide injection, as part of a reservoir simulation study, which will be covered in a subsequent publication; see
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.
Upon completion, the FPSO will be the first permanently fiber rope-moored offshore facility in the Mediterranean, processing the reservoir fluids and export sales gas from the Karish and Tanin gas fields offshore Israel. At nearly 3,000 tonnes, the company said its lift of an FPSO module was one of the heaviest land-based crane lifts ever performed. ALE was contracted to lift six modules for Total’s FPSO module integration project in Nigeria. The Leviathan gas platform has set sail from Corpus Christi, Texas, in the Gulf of Mexico to Israel, partners in the project said on 14 July. The Valhall Flank West topsides were installed on the Valhall field on 22 June, 14 months after the first steel was cut at Kværner’s yard in Verdal.
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.
Africa (Sub-Sahara) Bowleven has started drilling operations at the Moambe exploration well on the Bomono permit in Cameroon. Moambe is the second well in a two-well program, approximately 2 km east of the first well, Zingana. It targets a previously undrilled Paleocene Tertiary three-way dip fault block containing multiple sands and will be drilled to an estimated 1620 m in measured depth. Both wells will be logged. Bowleven is the operator and holds 100% interest. Asia Pacific Murphy Oil discovered gas at its Permai exploration well in deepwater Block H in the South China Sea offshore Malaysia. The find is Murphy's eighth consecutive success in the area around the Rotan floating liquefied natural gas project, which is planned to begin its first production in 2018.