The field development phase prior to investment sanction is characterized by relatively large uncertainties at the time important decisions have to be made. It is, for instance, crucial to select an appropriate recovery strategy (depletion or injection) to obtain optimal hydrocarbon cumulative production whilst ensuring good profitability of the project. Evaluation of reservoir as well as economic uncertainties and quantification of their impact are needed before the field development concept selection.
This paper describes how to stochastically assess reservoir and economic uncertainties and the screening process used to select the best recovery strategy. The chosen methodology is the combination of uncertainty studies, including both continuous, discrete and controllable parameters. The different screened scenarios are combined in a stochastic decision tree, built-up through decision and chance nodes, to establish a distribution of recoverable volumes and rank the recovery strategies given a chosen criterion. A second uncertainty study is performed by adding economic uncertainties to the initial set of reservoir uncertain parameters. Eventually a new decision tree is established and scenarios ranked using economic criteria.
The application of this methodology to an oil field from the Norwegian continental shelf and how recovery strategies are ranked are presented in this paper. The described methodology has exhibited the risks and uncertainties carried by the project, as it was possible to rank the different solutions based on the dispersion of the recoverable volumes distribution and/or on the net present value (NPV). In the context of a marginal or large capex project, a robust P90 case is required and this may therefore influence the choice of the recovery strategy. For instance, a scenario yielding the largest hydrocarbon volume may not be selected because it requires too many wells and/or too large investment if one of these criteria is defined as the most important. In addition, the combination of uncertainty studies enabled a full economic evaluation covering the entire recoverable volumes distribution whereas in many projects economic evaluation is focused on the P90, Mean and P10 scenarios.
The two-step integrated approach allows a decision to be made whilst taking into account both reservoir and economic aspects. Having a combined stochastic approach to the reservoir and economic uncertainties avoids a biased decision. All cases are stochastically covered and screened using a systematic and unified methodology that gives the same weight to each scenario.
Viscous oil recovery with steam injection is the most widely used onshore and offshore at present, and the oil-gas-water mixtures extracted by the method has some significant features when compared with the mixtures exploited by common recovery method. The yield, water-cut and temperature of mixtures at the wellhead, change periodically with steam injection. Due to the fluctuation of production, the steady-state simulation, which is common used in the design, cannot depict the characteristics of the process. Therefore, Aspen HYSYS Dynamic tool is selected to build a dynamic model which has a great conformance with actual production. The results show that dynamic simulation with Aspen HYSYS dynamic module, can accurately represent the fluctuation of flowrates, wellhead temperature, component and so forth, and with the dynamic method, the fluctuation of mixtures’ temperature can be obtained. It reveals the relationship of the yield, component and wellhead temperature along times, and indicate that the water cut of mixtures reach the lowest point in a period when the mixtures’ temperature is at its minimum. The heater loading is reduced by 20.9% by using the dynamic simulation tool at last. By putting the second batch of wells go into operation half cycle ahead of schedule, the design heat loading is reduced by 32.54%.
Process simulation is an analysis tool to calculate material balance and energy balance in petrochemical process and oilfield production, which is based on unit operation and thermodynamic principle. Aspen HYSYS is an excellent process simulation software, which is user- friendly and simple to operate. A new method to dynamically simulate coke deposition process for the delayed coking furnace is developed (Guo et al., 2008). In the design of conventional oil and gas fields, due to the change of production data in full life-cycle is not too fierce, steady-state simulation does a fine job of describing the production process. So, steady-state simulation method is widely used in the research and design of oil and gas field engineering. A processing plant of the Draugen platform by performing an energy and exergy analysis is evaluated (Nguyen et al., 2014). The life performance of an offshore platform by comparing three representative stages of an oil field is analyzed (Nguyen et al., 2014).
Zhou, Hongjie (Norwegian Geotechnical Institute, Perth, Australia) | Amodio, Alessandro (Norwegian Geotechnical Institute, Perth, Australia) | Rodriguez, Antonio Borges (Norwegian Geotechnical Institute, Perth, Australia) | Boylan, Noel (Norwegian Geotechnical Institute, Perth, Australia) | Deeks, Andrew (Norwegian Geotechnical Institute, Oslo, Norway)
During operation, the structural casings of a well experience two types of cyclic loads due to the heatingup and cooling-down of the well, which are: i) cyclic thermal induced forces on the structural casings themselves; and ii) cyclic thermal forces at the top of the structural casings generated due to the expansion and contraction of the inner casings and tubing (against the restraint from the structural casings). Combined with the nonlinear, hysteretic and degradable behavior of the surrounding soil, the interaction between the structural casings and surrounding soil have a significant effect on the overall performance of a well. This paper presents recent advances in the numerical modeling techniques of the well system, focusing on the axial interaction between the structural casings and surrounding soil under cyclic thermal loading. The complex structural casing - soil interaction under cyclic loading has been successfully modelled by using advanced cyclic t-z springs. The springs are integrated into a structural model representing the multistring well system and the associated cement. In the model, the soil specific behavior of the t-z spring is accounted for by calibrating the t-z model against laboratory model tests on the particular soils encountered along the structural casings. The developed modeling approach can capture the variation (e.g.
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.
New technologies that contribute to enhanced production in ultralong tiebacks have recently been developed. These new developments include higher differential pressure in multiphase pumps and compressors, mechanical designs for high pressures and temperatures, and power systems suited for ultralong tiebacks.
When developing new, cost-efficient boosting technology for long subsea tiebacks and deep water, a system approach is important. This includes power systems, installation methods, maintenance, reliability, and condition monitoring. The new technologies described have been developed based on operational experience and physical theory combined with practical experiments and validation, both scaled and full size. The importance of developing simple and reliable solutions in facilities that enables comprehensive experimenting and testing is also explained. Today’s oil and gas price level also requires cost-efficient solutions, and the paper explains how this can be obtained through standardization and modularization.
The first pump systems that are able to provide a more-than 200-bar differential pressure are already developed, qualified, and put in operation. A game-changing multiphase gas compressor technology that provides differential pressure up to 55 bar has also been built, tested, and verified. In parallel with these developments, subsea power systems have been further developed so that they can be used for step-outs longer than 200 km. Recently, a multiphase pumping station designed for 2,500-m water depth and 15,000-psi design pressure was installed and set in operation in the Gulf of Mexico. All of this contributes to enhanced production and lower field developments costs in subsea environments and provides a platform for further technology developments that can potentially make extremely remote subsea field developments economically attractive.
This paper presents new technology related to multiphase pumping and compression and a system approach that can make production from remote and deepwater subsea fields more capital efficient.
Seth, Gaurav (Chevron U.S.A. Inc.) | Valbuena, Ernesto (Chevron U.S.A. Inc.) | Tam, Soong (Chevron U.S.A. Inc.) | Da Sie, Will (Chevron U.S.A. Inc.) | Kumar, Hemant (Chevron U.S.A. Inc.) | Arias, Brian (Chevron U.S.A. Inc.) | Price, Troy (Chevron U.S.A. Inc.)
This manuscript presents the results and analyses from an integrated simulation study focused on evaluating and selecting subsea boosting systems. The integrated model uses field management strategies incorporating flow-line routing, field and gathering network constraints and rate allocation. Novel techniques to model subsea networks enable the selection of the boosting system and provide an improved understanding of dynamic conditions encountered in deep water assets. The selected boosting system ensures safe and reliable operations while improving the project's net present value.
Combining responses from reservoir and network systems into an integrated model to evaluate the subsea design requirements is a unique aspect of this study, as this involves novel modeling techniques for boosting systems (pumps). The robust approach ensures consistency of phase behavior across the system components, identification of pump requirements, production optimization and cost reduction. Analysis of these outputs leads to an improved understanding of field operation strategies, equipment selection and sizing, and production forecasts.
The integrated model uses Inflow Performance Relationships (IPR) from reservoir simulation and vertical lift tables to generate Performance Curves (PC), representing well deliverability as a function of Tubing Head Pressure. Comprehensive field management logic uses the PCs to determine optimal well operating rates that satisfy all subsurface and surface constraints. This approach reduces a complex set of constraints into a single operating rate. Well operating rate, is also a function of pump power, pump suction pressure and the fluid phase behavior across the pumps. The integrated model delivers pump performance within its operating envelope and ensures equipment integrity.
Two components of the subsea boosting system, single- and multi-phase pumps, drove performance optimization and selection of system operating conditions. The study incorporated a comprehensive analysis of system constraints through implementation of complex field management rules that accounted for well integrity (completions), performance of network equipment (valves, boosters, pump power requirements), facility capacities, and reservoir deliverability. The integrated study identified the different limiting system constraints throughout the life of the field and improved the overall efficiency of the gathering system. Use of PCs to reduce the constraints into a single operating rate provides tremendous computational performance improvement. Moreover, unlike typical optimization problems, adding more constraints to the system did not affect computational performance significantly.
Jøssund, Tor-Ole (Aker BP) | Elfenbein, Carsten (Aker BP) | Johansen, Yngve Bolstad (Aker BP) | Drange, Ingrid Sætre (Aker BP) | Olsborg, Lodve Hugo (Aker BP) | Skorve, Torstein (Aker BP) | Kvilaas, Geir-Frode (Aker BP) | Christoffersen, Kjell (Aker BP) | Mastad, Sigbjørn (Aker BP) | Stubsjøen, Marte (Aker BP) | Wang, Haifeng (Schlumberger) | Denichou, Jean-Michel (Schlumberger) | Charef-Khodja, Hakima (Schlumberger)
AbstractThe Ivar Aasen field was discovered in 2008 and consists of two main groups of reservoirs – the Jurassic and Triassic reservoir zones. The reservoir architecture is complicated by their different depositional settings and by syn- and post-sedimentary faulting. Developing a new field of such complexity is a challenging task that demands a novel approach to optimize well placement and improve reservoir characterization.Reservoir mapping while drilling (RMWD) technology has recently been introduced to the industry, providing an array of deep, directional measurements that are converted to a resistivity map of the formation out to approximately 30 m above and below the borehole. The reservoir mapping results are available for the operator to make geosteering decisions during drilling, to optimize the completion design with inflow control devices after TD, and to update the post-well reservoir model for planning the next wells. This process helps the operator maximize the benefits from the already drilled well on the yet-to-drill wells. The sequence of the wells to be drilled can be logically arranged to leverage the maximum value from the information that reservoir mapping provides.The drilling campaign on the Ivar Aasen field started in summer 2015 and the RMWD technology was used while drilling all the production wells. It revealed that the actual reservoir structure was even more complex than originally expected, and enabled the operator to pursue the best well path to maximize field production potential. This was achieved by using the data to actively geosteer, estimate reservoir producibility (through permeability-thickness calculation) in real-time to decide on TD, and by sidetracking to new targets revealed by the mapping. This new approach can also be applied to infill campaigns on existing fields. In this paper, one of the producer wells are reviewed in details to illustrate the process and demonstrate the results.
Spicka, K. J. (Nalco Champion, an Ecolab Company) | Eagle, L. Holding (Nalco Champion, an Ecolab Company) | Littlehales, I. (Nalco Champion, an Ecolab Company) | Fidoe, J. (Nalco Champion, an Ecolab Company) | Jordan, M. M. (Nalco Champion, an Ecolab Company) | Zosel, Z. (Nalco Champion, an Ecolab Company) | Glasser, S. (Nalco Champion, an Ecolab Company)
This paper highlights efforts taken in answering the following question: "Can horizontal unconventional shale wells be successfully squeezed for scale control?".
The Bakken shale formations in North Dakota, Montana and Alberta have presented unique operational challenges during the unconventional play boom. Despite the ability to control scale formation with conventional scale inhibitors under Bakken conditions, scale formation (primarily calcium carbonate) can still remain an operational challenge due to well design and sub-optimal scale inhibitor deployment.
Due to limited experience in the industry in scale squeezing fractured long reach horizontal wells, scale squeezes have not been frequently applied in the Bakken. As a result of sub-optimal scale control despite application of suitable scale inhibitors, an in-depth evaluation of scale squeeze chemistries, application methods and scale squeeze modeling has been ongoing in the Bakken. These successful applications are being studied to improve current scale squeeze modeling approaches for horizontal, fracked wells in addition to understanding the factors that impact Bakken scale squeezes. The lessons learned in modeling, application and monitoring of the scale squeezes will be discussed in this paper. Squeeze9 and Place-iT™ field history matching indicate the primary impact to squeeze life is the amount of scale inhibitor (both concentration and volume) used while overflush volumes have less of an impact. This varies from traditional scale squeezes that combine scale inhibitor and overflush volumes to achieve the desired scale squeeze lifetime. Due to the unique brine chemistry of the Bakken, squeeze monitoring has relied less upon traditional ion tracking and almost exclusively upon more advanced environmental scanning electron microscopy (ESEM) of suspended solids within the produced brine samples. Examples of successful Bakken squeezes lasting more than 1 year will be highlighted.
The successful applications of scale squeezes in the Bakken are bringing a new method of efficient, cost effective, long term scale control to unconventional plays. The lessons learned in the Bakken, and the resulting advancement of unconventional scale squeeze models and theories, have implications for the global industry as unconventional plays across the world are identified, explored and produced.
CO2 can be an effective EOR agent and is the dominant anthropogenic greenhouse gas driving global warming. Capturing CO2 from industrial sources in EOR projects can maximize hydrocarbon recovery and help provide a possible bridge to a lower carbon emissions future, by adding value through EOR production and field life extension, and providing long term secure storage post-EOR operations.
Shell is working to implement new generation CO2 projects, including offshore applications. Based on recent offshore project design experience, this paper describes the challenges in moving CO2 EOR from onshore to offshore and the solutions developed, in the key areas of safety, facilities, wells, subsurface and piloting. The overriding design principle in any project is HSE. Offshore operations brings a new set of challenges over inventory, pressure, confined spaces and evacuation, with conventional emergency procedures requiring modification because of the different physical characteristics of CO2 releases compared to hydrocarbon gas. Surface facilities need to be simple to minimise CAPEX, weight and space while maintaining flexibility, since there is less scope to incrementally evolve the surface facilities as is the case onshore. Balancing the tension between these objectives requires very close surface and subsurface integration to find optimal and cost-effective solutions.
This is illustrated with three key decision areas: gas treatment options for back produced CO2 and hydrocarbon gas, artificial lift and facilities capacity.
A novel integrated CO2 gas lift system is described. This simplifies facilities and reduces CAPEX and OPEX, while at the same time providing a high degree of flexibility and risk management over the EOR life cycle in terms of subsurface uncertainty and reducing the issues around molecular weight variation in the recycled gas and the degree of turndown required in the facilities in the early years of EOR operations.
CO2 is the dominant anthropogenic greenhouse gas that is believed to be driving global warming and climate change. Carbon capture and storage (CCS) is a technology that may contribute to reduction in CO2 emissions. However, CO2 capture from flue gas sources with current technology is CAPEX and energy intensive, so that the cost of CO2 abatement with CCS is high.
At the same time CO2 is an effective miscible flooding agent for EOR. Capturing CO2 from industrial sources for use in EOR projects can maximize hydrocarbon recovery and help provide a possible bridge to a lower carbon emissions future. Firstly, by adding value through additional oil recovery and field life extension, which can offset part of the cost of CO2 capture, and secondly, by providing long term secure storage after EOR operations have been completed.
Moving from onshore to offshore
Existing CO2 EOR projects are all onshore, with the majority of projects supplied with CO2 from natural subsurface sources. A minority of projects is based on captured CO2 from anthropogenic sources, with the largest being the Weyburn CO2 EOR and storage project, using CO2 captured from a coal gasification plant . Operating offshore CO2 injection has so far been restricted to storage of CO2 produced from gas processing plants, with the Sleipner  and Snøhvit  projects each injecting around one million tpa of CO2. Maximising value from disposal of CO2, (whether this is from low cost sources such as gas processing plants or more expensive flue gas capture) requires suitable EOR target fields, and in regions such as Europe and the Far East, large scale operations require moving CO2 EOR offshore into the major hydrocarbon basins.
The challenges facing offshore CO2 enhanced oil recovery (EOR) and carbon capture and storage (CCS) projects are presented in this paper along with potential solutions based on the oil and gas (O&G) industry's CO2 EOR and CCS experience and technology as applied in a few offshore locations. Prospects for future offshore projects are also discussed based on the O&G industry's experience, technology, and best practices. These achievements are the result of a safe and successful 58-year history of well construction and operations in land-based, commercial CO2 EOR projects.
Achieving CCS by injecting CO2 into saline formations or for EOR in mature oil reservoirs is a safe and effective method to reduce GHG (greenhouse gas) emissions. The IPCC has defined enhanced oil and gas recovery via CO2 injection as a recognized form of CCS. Using existing industry experience and technology developed over the past 58 years, CO2 injection into oil reservoirs for EOR has been safely and effectively applied in 18,077 active wells worldwide (17,112 in USA) according to the latest EOR survey (O&GJ, 2010). Production from natural gas reservoirs has also benefitted from CO2 injection in enhanced gas recovery (EGR) applications.
Key results are summarized and major conclusions presented from studies by the American Petroleum Institute; Advanced Resources International; European Commission, DG-Joint Research Centre, Institute for Energy; Kinder Morgan; Norwegian Petroleum Directorate; Bellona Foundation; Norwegian University of Science and Technology; SINTEF Petroleum Research; and others. Conclusions from these studies point to the substantial value of current industry experience as a sound basis for offshore CCS applications.
Offshore CCS/EOR may be more viable than onshore options for areas with high population densities, where offshore reservoirs are within reasonable distances from land, or where there are existing offshore O&G facilities and wells. The technical knowledge base of the petroleum industry can be leveraged for the development of CCS with a strong understanding of the pros and cons of offshore projects, operating experience with safe and economic CO2 capture, transportation, injection, and understanding of subsurface formations for future CO2 EOR/CCS applications.
Oil and Gas Industry Experience
The first patent for CO2 EOR was granted in 1952 (Whorton). The Texas Railroad Commission (TRRC report) proposed CCS rule states that "the first three projects (immiscible) were in Osage County, Oklahoma from 1958 to 1962.?? Another early CO2 EOR project was in Jones County, near Abilene, Texas in the Mead Strawn field in 1964 (Holm). The first large-scale, commercial CO2 EOR project (Langston) began operations in 1972 at the SACROC field in West Texas, which continues in operation today. Many more CO2 "flood?? EOR projects have started since then. By 2010, CO2 EOR projects had reached a global total of 127 (112 in USA) with 12 more planned for the USA, as reported in the EOR survey by the Oil and Gas Journal (O&GJ, 2010). Rising oil prices, low cost sources of high purity CO2, and access to miscible fields with large amounts of unrecovered oil have supported growth in CO2 based EOR in the U.S., which now accounts for 272 mbd (O&GJ, 2010) or over 8% of total Lower 48 crude production of 3.22 mmbd in the 2nd quarter 2010, as reported by the U.S. Energy Information