The so-called Digital Oil Field (DOF) is a somewhat ill-defined, misunderstood and abstract concept. The associated functional content, scope of work and terminology is variable from company to company and vague within companies. Consequently it is unclear how to gauge DOF degree of success, business benefit and effective organizational penetration. It is also sometimes unclear what the ultimate goals and associated road-maps are. With clear objectives, clarity of purpose and sufficient business justification there is a reasonable chance of meeting these goals, without clarity all is shrouded in mystique and uncertainty. Hence the purposes of this paper are to: Define precisely what is meant by the DOF; Describe the current operational status quo and compare and contrast with the ideal DOF; Define metrics that can be used to gauge the success of DOF initiatives. This will be achieved by illustrating what the DOF is, and what it is not, in terms of oil and gas field infrastructure, applications and experiences. Application of the metrics defined will allow users to determine whether it is "the beginning of the end, or the end of the beginning for their DOF."
A super-giant carbonate field in Abu Dhabi has most of its remaining reserves in carbonate build-up and prograding basinmargin deposits of Lower Cretaceous age (Shuaiba Formation). To guide further field production, a sequence stratigraphic framework was developed based on integration of core, log and seismic data. This framework is the cornerstone for building a new reservoir model and provides the key for a better understanding of facies and flow unit continuity guiding present and future field production and performance.Approximately 730 wells, wireline logs and the latest core descriptions were integrated for this study. Another key element was the incorporation of 3D seismic data coupled with several iterations between well log and seismic picking. Detailed seismic interpretation led to the delineation of 3rd and 4th order sequences. The picking of higher order sequences was based on well data guided by the seismic surfaces. This study provides an excellent example of extracting maximum information from seismic and the full integration of geoscience and production data to provide a new 3D framework.The sequence framework uses a consistent nomenclature based on the Arabian Plate Standard Sequence framework for the Aptian (van Buchem et. al., 2010). The Shuaiba is subdivided into six 3rd order sequences (Apt 1, 2, 3,4a, 4b, and 5) which, based on stacking patterns, record a complete 2nd order cycle of Transgressive, Highstand, and Late Highstand systems tracts (Apt 1-4b). The Bab Member (Apt 5) and Nahr Umr Shale form the Lowstand to Transgressive systems tracts of the next Super-sequence.The third order Apt 1 sequence and the Apt 2 TST form the 2nd order transgressive systems tract, characterized by backstepping and creation of differential relief between the Shuaiba shelf and Bab intra-shelf basin. These sequences are dominated by Orbitolina and algal/microbial Lithocodium/Bacinella fossil associations.The Apt 2 HST and Apt 3 Sequence form the 2nd order early highstand systems tract during which the platform area aggraded and the topographic split into platform, slope and basin became most pronounced. Sediments are extremely heterogeneous and varying properties introduce significant problems in understanding fluid flow. During the regressive part of the Apt 3 sequence accommodation space was limited and deposition switched to progradation at the platform margin. The platform top is characterized by thin cycles of rudist floatstones/rudstones separated by thin cemented flooding and exposure horizons, whilst the platform margin received large quantities of rudstones, grain and packstones organized in clinoform sets. Clinoforms are separated by thin stylolitic cemented layers, which are transparent on seismic.The Second Order late highstand systems tract is composed of 3rd order cycles Apt 4a and Apt 4b. These are detached from the main buildup, which probably stayed largely exposed, and form strongly prograding slope margin wedges composed of alternating dense mudstones (TST) and grainstone/packstone sequences...
The emerging trend in Oil and Gas industries for multi-disciplinary teams spread across diverse geographical locations is virtual team working. This concept is a key enabler in a digital oilfield environment where real time communication enables efficient decision making between field and office operations. The Shell Smart Fields Program, Shell's digital oilfield initiative, has deployed the use of Collaborative Work Environments (CWE) as an enabler to optimize operational value across its operating units globally.The fundamental pillars supporting a CWE implementation are 1) People, 2) Work Process, 3) Tools and Applications and 4) Facility. During the design and implementation phases of building a CWE, emphasis is typically placed on work process, tools and applications, and facility while the people aspect is embedded within other improvement areas. The Smart Fields Program has observed that integration of the People aspect is critical to ensure a CWE's success. Without an effectively and efficiently trained workforce, the new CWE processes will not flow as intended. To address this, Shell has developed a tested methodology focused on driving the required behavioral change to achieve the necessary performance. This paper will focus on the importance of the people aspect in a CWE implementation, based on a 2009 improvement effort centered on Human Factors Integration (HFI) and behavioral change coaching. In particular, this paper will address:• The role of HFI / coaching in CWE implementations • Identification of relevant people issues • How to provide continued / ongoing support to the 'digital' workforce • Identification within the organization of ownership for the new collaborative behaviors • The necessary organizational structure required to support new ways of working • Required behavioral changes to support the future workforce • Key differences between staffing operations in a current oilfield versus a digital oilfield • Lessons learned from deployment of above points
Two 126 level 3-component 3D-VSP's (Vertical Seismic Profiles) were acquired coincident with a high-resolution surface seismic survey. Figure 1 shows the location of the first 3D-VSP on the crest of the field and the second 3D-VSP on the flank of the field. Using the surface seismic sources, 11712 shot points were used per VSP to collect 4.5 million traces per VSP, which produced a 6–9 km2 final 3D-VSP image around each of the two wells. Due to the large offsets and high density of traces available it was possible to experiment with acquisition and processing methodologies to produce images that resolve thinner beds, see more structural definition and improve reservoir characterization. Results from the first phase of processing are very encouraging and show the 3D-VSP images to be able to resolve subtle faults that were not seen in older surface seismic data and have higher frequency content than the new 640 fold, high resolution surface seismic data. Source and receiver decimation tests are aiding in efforts to better understand how to acquire high quality 3D-VSP's in the future with minimal effort and cost. Efforts to expand the size of the 3D-VSP volumes around the wells have been successful. The largest image produced so far has been able to image more than 1.5 km away from the wellbore. The high quality VSP images and the fact that VSP's can be repeated at much lower cost than surface seismic makes this technology very attractive for future time-lapse reservoir monitoring studies.
An important carbonate oil field, located onshore Abu Dhabi, has been producing from the Upper Cretaceous (Maastrichtian) Simsima Formation since 1983. To optimize and increase production of the field, seismic and high-resolution sequence stratigraphy was integrated by tying fourth-order, high-frequency sequences identified from core to 3-D seismic data. To establish the sequence stratigraphic framework, a new detailed sedimentological and high-resolution sequence stratigraphy study had been carried out, integrating approximately 7,000 feet of core material, approximately 3,500 thin sections, and all available well-log data from 46 wells. Core description, together with semi-quantitative petrographic examination of thin sections, established a new depositional model for the Simsima Formation. Sixteen lithofacies types (LF1 to LF16) representing a wide variety of depositional environments, ranging from upper ramp, rudist-bioclastic shoals to open marine mid to outer ramp mud-dominated settings. The newly developed, high-resolution sequence stratigraphic framework suggested that the Simsima Formation comprises one complete third-order composite sequence and the transgressive systems tract of an overlying second third-order composite sequence. These third-order composite sequences include seventeen high-frequencies, fourth-order sequences (HFS). HFS-1 to HFS-12 build the older third-order composite sequence, HFS-13 to HFS-17 form the transgressive system tract of the overlying, younger third-order composite sequence. 3-D seismic cross-sections show that fourth-order high-frequency sequences HFS-1 to HFS-6 of the older third-order composite sequence clearly show onlap on a pre-existing high (pre-Simsima unconformity surface), whereas the top part of the Simsima Formation (high-frequency sequences HFS-13 to HFS-17) show various degree of erosion. The established high-resolution sequence stratigraphic framework provides the layering scheme for the next generation Simsima 3-D static model, which will be used as input for the reservoir flow (dynamic) model. Introduction Large oil accumulations have been discovered and produced from the Upper Cretaceous (Maastrichtian) Simsima Formation in Abu Dhabi since 1983. The Simsima Formation was deposited on an actively growing paleo-high in shallow marine environment. It is capped by the basal shale member of the Umm Er Radhuma Formation and overlies the crest of partly eroded former structure of the Aruma Group. It ranges in thickness from 323 ft in the crest of the field structure to 628 ft in the flank. Recently, approximately 7,000 feet of core and 3,500 thin sections along with well-log data from 46 wells were studied. A total of sixteen lithofacies types were identified. As a result of the core study, seventeen high-resolution fourthorder sequences were established. They constitute a complete third-order composite sequence and the transgressive systems tract of an overlying second third-order composite sequence. The high-resolution sequence stratigraphy identified from cores was integrated with the 3-D seismic by tying the fourth-order sequences to the seismic data. An integrated layering scheme will be used for the next generation Simsima 3-D static model, which will be used as input for reservoir flow (dynamic) model.
The 3D architecture of flow units is a key parameter influencing production and recovery from oil reservoirs. Depositional facies and their 3D stacking patterns are commonly fundamental building blocks of flow units. Hence, the recognition of facies, and their placement in conceptual depositional environments is the basic requirement to establish 3 dimensional architectural models of reservoirs. In order to establish facies, facies stacking patterns and the 3D architecture of a super giant field contained in the Aptian in onshore Abu Dhabi , detailed sedimentological and petrographic core description have been carried out using about 13000 ft of core from a total of 49 cored wells. In total 27 facies have been established using fabric and bio content. They have been placed into conceptual depositional models following an evolving platform to basin topography during transgressive, early highstand and late highstand phases of carbonate platform development during the Aptian. This paper presents a comprehensive facies atlas that contains for each facies a detailed description of fabric and bio content, core and thin section pictures, petrophysical summaries and an interpretation of depositional environment. The large areal distribution of core coverage over more than 800 square km paired with the location of the reservoir transgressing platform interior to basinal settings ensures a comprehensive coverage of facies typical for most of the Aptian. The study developed an updated and unified facies scheme embedded in the existing interpretation of the depositional environments and high resolution sequence stratigraphy, and completed the core facies scheme definition which is understood as a fundamental criteria for the population of 3D static and dynamic model, in order to effectively enhance future reservoir development.
How can you effectively manage the wells if you do not continuously know what they are producing? This is even more the case when the wells are being started-up for the first time. FieldWare Production Universe (PU) is Shell's real time well Virtual Flow Measurement (VFM) tool, which is running on 60% of Shell's global production and has enabled significant added value in the areas of real time surveillance and optimization. Production Universe has now been applied in the start-up of a number of Shell offshore projects in the Arabian Gulf and the Gulf of Mexico. The purpose of this paper is to describe PU added value that has been achieved in the following areas of these project start-ups under transient and steady state operations:"Provision of well flow estimates from the very start of commissioning for early indications of well/reservoir performance"Provision of well flow estimates from the very start of commissioning for more accurate hydrocarbon accounting/allocation;"Calculation of gas flaring volumes from the very start of commissioning, again for more accurate hydrocarbon accounting and GHG emissions;"Replacing wet gas flow meters on individual offshore wells with equivalent virtual flow meters, hence saving significant CAPEX and OPEX;"Replacing offshore bulk flow measurement for total platform gas and liquid exports with the sum of the aforementioned well virtual flow estimate, again saving significant CAPEX;"Control of corrosion/hydrate prevention chemical injection ppm based on well flow estimates resulting in enhanced pipeline integrity and chemicals OPEX savings Introduction and background Shell has had a number of large upstream, offshore projects recently in various stages of start-up and/or commissioning. These projects are critical in terms of large capital investment, reserves contribution and degree of difficulty (very deep water, subsea processing, long subsea multiphase pipelines, feeding large onshore gas plants etc.). Hence it is imperative to start-up the processes as quickly and efficiently as possible and yet maintain the highest possible standards of technical integrity, safety and environmental impact. Key aspects for efficient/effective project start-up are well/reservoir surveillance and hydrocarbon accounting - it is important to know how much the wells are producing and the composition of the fluid streams, for maximum production, flow assurance, asset technical integrity and accounting purposes. Ideally this would be achieved by using Multi-phase Flow Meters on each of the wells to physically and continuously measure the oil, gas and water flows, or by routing the wells to the Test Separator as they are progressively started-up. However, MFMs may not have been installed for all wells, and for wells that have them, they are usually not commissioned at the time of well start-up ?? MFM commissioning requires fluid samples from the wells - for subsea wells sampling is usually done robotically and at a later start-up stage. However, Virtual Flow Meters (VFMs) can be operational from the very start of production. Similarly, test separators may not be commissioned at the time of initial well production and if they are operational they are not suitable for tracking production from multiple wells. Hence, VFM is of significant value for well/reservoir surveillance and hydrocarbon accounting from the first instance of start-up, up to the time when MFMs are effectively commissioned and thereafter as effective insurance in case of individual meter failure. VFMs have also been used for the following:"replacing wet gas flow meters by continuously estimating well flows, incurring significant CAPEX and OPEX savings;"replacing offshore bulk flow measurement for total platform gas and liquid exports with the sum of the aforementioned well virtual flow estimates, again saving significant CAPEX and OPEX;"continuous calculation of gas flaring volumes from the very start of commissioning, again for more accurate hydrocarbon accounting (ref 8);"continuously estimating chemical injection ppm, hence correcting for well flow changes and safeguarding pipeline technical integrity by always ensuring the right dosage;"saving OPEX by minimizing chemicals injected. In most Shell EP operating companies a real-time software application known as FieldWare Production Universe (PU) is used for VFM, providing a continuous indication of oil, gas and water flow for all wells. PU is a data driven modeling application developed by Shell ?? the development background and operational experience within the Shell Group have been extensively described - see references 1, 2, 3, 4, 5, 6, 7. Using data driven models, PU provides a "virtual" three phase meter for all of the wells, all of the time. An overview description of PU follows.
Profile modification of injection and production wells is of major importance in South Oman heavy oil reservoirs. This is because injected and produced water must be controlled to optimize reservoir sweep and oil production. Profile control in artificial lift wells is also a common dilemma because the intervention involves re-completing wells to achieve logging-while-pumping necessary for detecting unwanted intervals. In 2004, two completion philosophies were adopted to allow hoist-free re-entry as well as provide a cost effective life-cycle solution. One is the replacement of smart wells with segmented horizontal wells. This completion allows for effective diagnosis and isolation of watered-out sections. The other is replacing the upper completion of producers in sub-hydrostatic reservoirs with dual Christmas Trees. That makes it possible to measure the inflow profile while pumping through the second tubing. A proactive measure was taken by field-testing a new technology capable of satisfying all basic requirements. The technology is a wireline deployed rubber and carbon fiber sleeve expanded by hydraulic pressure to set flush against the casing. Heat is applied to polymerize the resin before deflating and retracting the running tool. The patch thickness can withstand both burst and collapse pressures, leaving sufficient internal-diameter in 7-in and 4 ½-in casing for subsequent deeper intervention. Phase-1 trial was successfully completed in 3 water injectors late in 2004. Phase-2 trial which was planned for 2 oil producers are still being mobilized and will be executed in third quarter of 2005, late for publication in this paper. Some unique characteristics of this technology made it attractive; namely (1) ability to deploy via smaller size tubing to expand & set in larger perforated liners, thus eliminating rig/hoist requirement, (2) high depth precision using CCL correlation, (3) possibility of bypassing existing patch to isolate downstream toe area, (4) possibility to by-pass isolated areas to re-perforate lower zones and safely retrieve the bloated gun barrels, (5) applying gentle and even hydraulic force contour-to-contour to set against un-reinforced liners, (6) cost effective solution of higher success rate compared to chemical treatments. The trials proved to be the first campaign of its kind to be successfully completed with 100% success rate, while meeting all expectations. Introduction As part of the new effort to reverse the trend of increasing water cut in Petroleum Development Oman (PDO), both mechanical and chemical profile control initiatives have been widely pursued in the Southern and Northern Directorates. PDO currently produces 630,000 bbl/d of oil with about 3.6 Million bbl/d of water - 85% water cut (WC) - and this is expected to remain on the rise unless life cycle remedial solutions are implemented to mitigate this trend in both the existing and new wells. Southern & Northern Oman Directorates are predominantly sandstone and carbonate formations respectively, meaning that their development challenges and costs are somewhat dissimilar. Also, formation & reservoir fluid properties are known to vary widely from North to South. Due to these differentiating qualities, a viable optimization solution in the South might not be found optimal in the North and vice-versa. For example, the South mainly employs a lot of Beam (Rod) Pumps and some Electric Submersible Pumps (ESPs) while the North depends mainly on Electric Submersible Pumps (ESP) and Gas Lifts. While these directorates are currently operated as two different business units in terms of development methodologies, optimization techniques, etc, they however share one common goal of maximizing production at a reduced operating expenditure. The primary aim being to restore oil production to 800,000 bbl/d over the next few years.
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