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Ultra-high-pressure high-temperature (uHPHT) reservoirs undergo extreme pressure depletion during their production life cycle. This results in significant reservoir compaction and consequent overburden subsidence with major consequences for wellbore mechanical integrity, safety, and field economics. However, the use of underdetermined geomechanical models to accurately predict compaction-induced stress/strain changes on wellbores and its consequences during production time results in significant residual uncertainty. One method of measuring compaction-induced stress/strain changes in wellbore is by the emplacement and measurement of radioactive markers. Although it is long established in normal pressure reservoirs, it is rare in uHPHT projects.
The Culzean uHPHT gas-condensate field is located in the UK Central North Sea. To constrain geomechanical model compaction uncertainty, radioactive markers were deployed. The objective was to accurately acquire preproduction baseline measurements and subsequent changes through periodic measurements during production life. These accurate wellbore measurements would then be compared with the geomechanical model to help calibrate predicted to actual compaction. By doing so, the objective is to enable better informed decisions regarding well and field management. The Culzean uHPHT radioactive marker project comprised a planning phase and a preproduction safe deployment including a baseline survey phase. Subsequent repeat measurements are planned during field production life.
The emplacement and surveying of the subsurface radioactive markers for compaction monitoring in uHPHT reservoirs is a high value but nontrivial operation. In addition, much knowledge and experience of the methodology has been lost. This paper contributes to published literature by describing the successful emplacement and monitoring of subsurface radioactive markers on Culzean and aims to capture learnings and knowledge for future workers. Early detailed planning coupled with extensive testing is key to successful deployment. Timely engagement of all stakeholders and ensuring all decisions are aligned with safety and environmental considerations also contribute to realization of the project aims.
French, Simon (Ophir Energy) | Puspitasari, Ratih (Schlumberger) | Isherwood, Alison (Ophir Energy) | Cox, Phil (Ophir Energy) | Marsden, Rob (Marsden Rock Consulting) | Edo Mbang, Manuel Ndong (GE Petrol) | Tan, Chee Phuat (Schlumberger) | John, Zachariah (Schlumberger)
This paper presents a comprehensive workflow for determining reservoir compaction and seabed subsidence through a case study on a deepwater gas development in Equatorial Guinea. It shows how a 4-D coupled reservoir geomechanical model can be used to evaluate well integrity risk with reservoir pressure depletion and outlines how the results and findings drive key decisions in the planning of the field development and design of the wells.
The workflow includes constructing and calibrating single well geomechanical models that are up-scaled and combined with seismic, structural model and reservoir model to create a field wide 3-D geomechanical model. Coupled numerical simulations with this model provided predictions of geomechanical phenomena for the projected field life with modified Cam-Clay method accounting for pore collapse in the reservoir sands. 4-D coupled simulation results on deformations, fracture gradient, breakout and breakdown mud weights were generated for mitigation of drilling hazards at field scale rather than the more traditional well-by-well analysis. Further numerical simulations of the completion well casing and cement provided well operability risk.
The magnitude of compaction in the upper and lower reservoirs was predicted to be several metres, corresponding to maximum and average reservoir strain of 6% and 3%, respectively. The majority of the reservoir compaction was transmitted to the seabed in the form of subsidence due to the thin and soft overburden. The 4-D simulation results were used effectively to visualize well performance risks in different areas of the field which allowed optimisation of well locations and timing of drilling. The mechanical integrity of the completions, well casing and cement were assessed by incorporating the output from the full field model into a near-wellbore model where material strains and plastic deformations were calculated. Impact on well operability was determined by referencing to data from published literatures and other projects. A telescopic contraction joint will be incorporated into the open hole gravel pack lower completion design to protect the completion from damage due to the high axial strain predicted in the string. Loss of production casing annulus cment integrity is also identified to be a risk which is mitigated by careful cement placement to ensure long term barrier integrity.
Traditionally for such analyses, either an analytical method based on elastic deformation and lab data or a numerical method decoupled from the reservoir using relatively simple constitutive models are used. Both these approaches could under predict compaction for such unconsolidated formations. Herein, volumetric failure (pore collapse) has been fully accounted for within the model. In this study, utilisation of the latest techniques in advanced 4-D coupled reservoir geomechanical modelling reduce the study time and costs significantly, making it affordable for in-time solutions suitable for decision making to the drilling and completion team.
Downhole fluid samples enable better quantification of condensate-to-gas ratios that are required for effective reservoir estimation and forecasting. Quality of samples directly affect the measured properties, i.e., fluid compressibility and viscosity, that provide the supplemental information necessary for planning prospective wells through improved understanding of the reservoir. An industry-leading, logging-while-drilling (LWD) fluid analysis and sampling tool was successfully deployed on 21 jobs with 46 runs to date, and completed 400 pressure tests with 109 samples recovered worldwide in shelf and deepwater projects. This paper highlights a new systems application for this technology to acquire single-phase fluid samples for a major operator in Trinidad. The acquired data was used for early investigation of reservoir connectivity. The technology was introduced to the oil and gas industry in 2011.
Sun, Haifang (CNPC, CCDC, DPRI) | Bai, Jing (CNPC, CCDC, DPRI) | Huang, Bing (China Natl. Petroleum Corp.) | Chen, Weiqing (CNPC, CCDC, DPRI) | Hong, Yuandong (Shell China, Co.) | Moh, Thomas (Schlumberger China SA) | Zhou, Feng (CNPC, SWOGC)
Copyright 2014, Offshore Technology Conference This paper was prepared for presentation at the Offshore Technology Conference Asia held in Kuala Lumpur, Malaysia, 25-28 March 2014. This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright. Abstract Low cost, high technology and fast rate of penetration (ROP) are three main factors which related to successful development of unconventional shale gas all over the world  . Local operator and international operator use different approaches to develop shale gas in Sichuan basin, where is a hot place for shale gas chasers in China.
E-log provides not only reservoir parameters to evaluate hydrocarbon reserves but also geological information on erosion thickness in addition to sedimentary environments (Pirson, 1970 and Zimmerle, 1995). Erosion thickness is one of the key issues for hydrocarbon generation, expulsion, migration and trapping in oil and gas exploration.
Although there are several methods to estimate erosion thickness, two kinds of methods were applied in this study for reasons of practicality and accuracy, namely; i) conventional reconstructed section method; and ii) Magara method (1978) with use of sonic logs. Magara method is the only method which uses sonic logs to estimate erosion thickness based on shale compaction trend.
Shale compaction method was applied to the Pattani Trough of the Cenozoic basin in the Gulf of Thailand for 122 wells in 13 oil and gas fields. However, the method gave extraordinarily large values for erosion thickness of the Middle Miocene Unconformity (MMU) compared to the results of conventional reconstructed method because of the high velocity of Sequence 4 located immediately below the MMU. The main reasons for the high velocity of Sequence 4 are considered to be: a) hardening by hydrothermal water; b) high concentration of certain rocks or minerals such as calcite, iron, pyrites etc.; and c) alternation of clay mineral by heat through “chemical compaction” (Pollastro, 1993 and Bjorlykke, 1999).
It is evident that a hydrothermal event occurred locally in the Pattani Trough (Sasaki, 1986 and Fujiwara & Sasaki, 1988). Mud logs obtained at 7 wells and the temperature gradient derived from bottom hole temperature (BHT) at more than 70 wells were reviewed. There appears to be no strong relationship between lithology and the high velocity of Sequence 4 and temperature gradient is high [2.74°F / 100 feet (4.99°C / 100 m)] on average which is almost identical to the island of Sumatra in Indonesia. Therefore, alternation of clay mineral from smectite to illite conversion under high temperature conditions is one of the main factors that explain the high velocity of Sequence 4.
In case of application of the Magara method in hot basins such as those in South East Asia, careful attention should be paid. Conventional reconstructed section method is also recommended together with the Magara method.
Two important trends affecting the expected growth of global gas markets are (1) the shift by many industrialized countries from coal-fired electricity generation to the use of natural gas to generate electricity and (2) the industrialization of the heavily populated Asian countries of India and China. This paper surveys discovered gas in stranded conventional gas accumulations and presents estimates of the cost of developing and producing stranded gas in selected countries. Stranded gas is natural gas in discovered or identified fields that is not currently commercially producible for either physical or economic reasons. Published reserves of gas at the global level do not distinguish between volumes of gas in producing fields and volumes in nonproducing fields. Data on stranded gas reported here--that is the volumes, geographical distribution, and size distributions of stranded gas fields at the country and regional level--are based on the examination of individual-field data and represent a significant improvement in information available to industry and government decision makers. Globally, stranded gas is pervasive, but large volumes in large accumulations are concentrated in only a few areas.
The cost component of the paper focuses on stranded conventional gas accumulations in Africa and South America that have the potential to augment supplies to Europe. The methods described for the computation of extraction and transport costs are innovative in that they use information on the sizes and geographical distribution of the identified stranded gas fields. The costs are based on industry data specific to the country and geologic basin where the stranded gas is located. Gas supplies to Europe can be increased significantly at competitive costs by the development of stranded gas. Net extraction costs of producing the identified gas depend critically on the natural-gas-liquids (NGLs) content, the prevailing prices of liquids, the size of the gas accumulation, and the deposit's location. The diversity of the distribution of stranded gas is one obstacle to the exercise of market power by the Gas Exporting Countries Forum (GECF).
The future profitability and the ultimate hydrocarbon recovery of North Sea fields are largely dictated by the management of the infrastructure used to process and transport hydrocarbons. Optimization of this infrastructure is therefore an important strategic objective for most North Sea players.
In the North Sea, a common offshore infrastructure design consists of a regional hub that collects hydrocarbons from the fields located in the catchment area. This collective production is exported by a pipeline leaving the hub. Hubs, pipelines and oil-and-gas receiving terminals are typically paid a tariff for their services. Once tariff receipts become insufficient to cover the costs of those services, many commercial agreements default to cost-sharing arrangements, where the operating costs of the facility are distributed over its user-fields1. This cost sharing generally translates into higher operating costs for these fields and may cause certain user-fields to become uneconomical. As one user-field ceases production, the infrastructure facility's operating costs are distributed over fewer fields. This may translate into a "domino-effect?? scenario, in which more and more fields become uneconomical, thereby cutting short the economic life of the infrastructure facility.
In this paper, the economic interdependencies between a hub and its user-fields are illustrated first by a generic example, then by an analysis of the Bruce hub and its user-fields in the UK North Sea. The results highlight that accurate modeling of hub and user-fields interactions can increase understanding and mitigate the risks of potential "domino-effects??, in which the economics of transportation and processing facilities may deteriorate rapidly and turn large segments of the North Sea uneconomical.
Probabilistic aggregation and dependency estimation are essential in portfolio methods, production forecasting, and resource estimation. The use of arithmetic addition understates the true value of the resource estimates within a portfolio of fields. Potentially, this could result in deferral of a project, or loss of lucrative business and commercial opportunities, such as project investment, facility-sizing decisions, or incremental gas-supply commitments.
A statistically robust method for aggregation of resource estimates that appropriately uses expert opinion is presented in this paper. Using two integrated-project examples, this paper introduces new methods for (1) probabilistic aggregation of the resource estimates for multiple fields and (2) estimating a measure of dependency between the resource estimates of individual fields.
The new analytical method for probabilistic aggregation is based on multivariate skew-normal (MSN) distributions, which can model a wide range of skewness through a shape parameter and are used heavily in financial and actuarial applications.
In studies of the fields in which the multiple-realizations approach is used as a basis for the uncertainty framework, tornado diagrams are generated routinely to describe the dependence of the field resources on reservoir parameters. The improved method for evaluating measures of dependency between the resource estimates within a portfolio of fields uses these tornado diagrams as a basis. Incorporating the expertise and knowledge of geologists and petroleum engineers is a critical element of the method.
These methods for probabilistic aggregation and estimating dependencies were developed within the context of the oil industry, but their use is not limited to the oil industry. They are general and can be used in other probabilistic-aggregation problems. Application of these techniques requires limited time and effort, compared to individual-field studies, and can have a profound impact on the uncertainty range of the total resources for the portfolio of fields.
This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 19082, "Espirito Santo: The New Deepwater Frontier in Brazil," by Marcio Felix Carvalho Bezerra, SPE, and Nery Vicente Milani De Rossi, SPE, Petrobras, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May.
Petrobras has been active in five simultaneous exploration and production frontiers in the Espirito Santo basin, namely gas in shallow water, light and heavy oil in deepwater, and light oil in ultradeep water and onshore. Petrobras has invested in new infrastructure projects including pipelines, processing plants, and a new port to support offshore operations. The company also has participated in research projects in partnership with the Federal University of Espirito Santo.
Petrobras’ activities in the state of Espirito Santo, in southeastern Brazil, encompass the Espirito Santo basin (onshore and offshore) and the northern portion of the Campos basin (offshore). Activities began in 1957 with an onshore focus. In 1968, Brazil’s first offshore well was drilled in the Espirito Santo basin. In 1978, the Cacao field was the first offshore commercial discovery in the Espirito Santo basin, in a water depth of 19 m.
Onshore production began in 1973, reaching maximum production of 25,000 BOPD in 1984, declining to 9,000 BOPD in 1998, when new fields were discovered by use of new technologies (e.g., 3D seismic). In early 2001, the first commercial deepwater discovery was the Jubarte field in the northern Campos basin, followed in 2003 by the discovery of light oil in deep waters in the Espirito Santo basin (Golfinho field).
Jubarte. Production began with a 2-month extended well test (EWT). This field produced approximately 20,000 BOPD through the Seillean float-ing production, storage, and offloading (FPSO) vessel. Phase-1 field develop-ment began December 2006 through FPSO P-34 with a production capacity of 60,000 BOPD. Phase 2 is planned for 2010 through FPSO P-57, with a capacity of 180,000 BOPD.
Heavy-oil-production technologies include use of long horizontal wells to increase the production, use of electrical submersible pumps (ESPs) installed on the seabed as the main artificial-lift method with gas lift as backup, and the conversion of the FPSO P-34 to process heavy oil.
Neighboring the Jubarte field, Cachalote, Baleia Franca, and Baleia Ana fields were discovered in 1500-m water depth. Production is scheduled to begin in 2012. The Baleia Azul field (1300 m water depth), south of Jubarte, may begin operation in 2014. The Caxareu, Pirambu, and Manganga fields were discovered in 2006 and are in the study phase to define the production systems.
The Nautilus, Abalone, Ostra, and Argonauta fields are being developed in two phases, with the first phase in 2009, through an FPSO with capacity for 100,000 BOPD.
Catua. The Catua field (in water depth of 1800 m), is 50 km southeast of Jubarte and contains 42°API oil in a carbonate reservoir. Discovered in 2005, an EWT is planned for 2008 to define the technical and commercial feasibility.