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Results
How Economic is Steam-Assisted Gravity Drainage for the In-situ Development of the Nigerian Bitumen Deposit?
Lawal, Kazeem A. (Shell Nigeria Exploration & Production Company)
Abstract This paper details a preliminary evaluation of the economics and commercial risks of deploying the steam-assisted gravity drainage (SAGD) technique for the in-situ extraction of the oil component of the Nigerian tar sands. The workflow consists of parameter screening, experimental design, response-surface generation and Monte-Carlo simulation. With the net present value (NPV) as the objective function, we evaluate the impacts of the reservoir models (oil production and steam-injection profiles), project costs, hydrocarbon (oil and gas) price and the fiscal regime on project economics and commerciality. Within the range of parameters investigated, the uncertainties associated with the reservoir model, oil price, operating expenditure (OPEX) and capital expenditure (CAPEX) are found to be the main determinants of the commercial risks of the project. The fiscal policies do not appear to have much impact, at least within the parameter space examined. Overall, it is estimated that SAGD has more than 60% chance of economic success (NPV > 0), suggesting that this recovery technique is commercially attractive for the in-situ exploitation of the Nigerian bitumen deposit. The commercial prospects of this technique notwithstanding, the potential risks are highlighted, while options for mitigating such risks within the Nigerian context are discussed.
- Africa > Nigeria (1.00)
- North America > Canada (0.69)
- Africa > Togo > Dahomey Basin (0.99)
- Africa > Nigeria > Dahomey Basin (0.99)
- Africa > Ghana > Dahomey Basin (0.99)
- Africa > Benin > Dahomey Basin (0.99)
Validation of a Pseudocomponent Scheme for Nigerian Heavy Oil and Bitumen
Lawal, Kazeem A. (Shell Nigeria Exploration & Production Company)
Abstract Recently, a set of six pseudocomponent (PC) schemes was proposed for general characterisation of the Nigerian heavy oil and bitumen 1. However, the performance of the schemes is yet to be assessed. Given the laboratory-measured viscosity versus temperature relationship of a sample of the Nigerian bitumen, this paper employs the PC schemes to construct and tune fluid models to the viscosity dataset. Although all the cases show reasonable agreements (average absolute deviation below 25%) between measured and fitted data, the best and worst performances are obtained with the 4-PC and 1-PC schemes, respectively. The tuned fluid models are then applied in thermal reservoir simulation studies. With a generic but representative reservoir-sector model, the dynamic response of the Nigerian bituminous deposit to the recovery method of steam-assisted gravity drainage (SAGD) is investigated. Simulation results indicate excellent consistency among the 3, 4, and 5-PC schemes but the 1- and 2-PC schemes deviate markedly from the higher-component approximations. As might be expected, the 1-PC model can not explain the solution gas reported in the Nigerian bituminous belt. From the specific case studied, at least three PC's may be required to enable satisfactory characterisation of the Nigerian heavy crude for general applications. This initial conclusion follows from the comparative accuracy and computational efficiency of the ternary (3-PC) model. Future efforts should focus on generating additional experimental datasets, including but not limited to viscosity, on the Nigerian bitumen and evaluating the robustness of our preliminary conclusion.
- Africa > Nigeria (0.69)
- North America > United States > California (0.28)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.68)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
Sedimentary Controls on Porosity and Permeability in Deepwater Turbidites
Njoku, Chukwueke (Shell Nigeria Exploration & Production Company) | Pirmez, Carlos (Shell Nigeria Exploration & Production Company)
Abstract Knowledge of the sedimentary controls on porosity and permeability is important in the exploration and production of oil and gas in various depositional settings. In deepwater reservoirs this is even more important because of the high cost of development wells. Few studies of porosity and permeability in deepwater reservoirs are available. We report on the main controls on porosity and permeability of deepwater reservoirs using core plug samples from several wells in Shell's deepwater portfolio. Results show that grain size control on permeability and sorting control on porosity and permeability are well reflected in the turbidite and debrite facies.
- North America > United States (0.28)
- Europe > United Kingdom (0.28)
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.67)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 49/27 > Leman Field > Rotliegendes Formation (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 49/26 > Leman Field > Rotliegendes Formation (0.99)
Reconciling and Improving the Volumetrics of Nigerian Heavy Oil and Bitumen Resources
Lawal, Kazeem A. (Shell Nigeria Exploration & Production Company)
Abstract Despite being penetrated by over 100 wells, and more than a century of studies, the in-place and recoverable volumes of oil resources within Nigeria's bituminous belt are still inconclusive. Noteworthy is the misleading appropriation of "reserves" to the deposit. While there is an obvious motivation to improve the current situation, credibility requires that such efforts are premised on a combination of reliable dataset and robust method of study. This article is an attempt at reconciling and improving current estimates of the hydrocarbon potentials of the Nigerian bituminous belt. It reviews and integrates numerous datasets on the belt. Reasonable assumptions, empirical correlations and analogue information are used to mitigate identified data gaps while recognising uncertainties. With estimated input data and associated uncertainties, deterministic and probabilistic techniques are employed for robust volumetrics. Unlike previous studies, we consider solution gas. Using performances of some proven exploitation technologies in provinces of comparable reservoir and fluid characteristics as Nigeria's, we make reasonable estimates of recovery factors, and establish cumulative distribution curves for recoverable (not reserves) volumes of discovered bitumen, heavy oil and oil shale deposits, including the dissolved gas content. From the analyses, we estimate 71, 207 and 415 billion barrels as the P90, P50 and P10 stock-tank oil in-place volumes, respectively. Corresponding solution-gas quantities are 1.4, 5.0, and 13.6 Tscf, respectively. Compared to current official record of about 43 billion barrels, which does not account for the field-proven solution gas, potentials of Nigeria's bituminous belt may be significantly underestimated at present. Although the volumetric ranges in this study reflect the relative magnitude and impact of uncertainties, sensitivity analysis indicates that reservoir extent and thickness as well as solution gas-oil ratio are the main uncertainties. Consequently, a key objective of future appraisal programs should be to narrow the current range of (static) uncertainties.
- Africa > Nigeria (1.00)
- North America > Canada > Alberta (0.28)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.74)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.35)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Keathley Canyon > Block 384 > Colonial Field (0.95)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Keathley Canyon > Block 383 > Colonial Field (0.95)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
An Improved Estimation of the Storage Capacity of Potential Geologic Carbon-Sequestration Sites
Lawal, Kazeem A. (Shell Nigeria Exploration & Production Company)
Abstract The ideas of open and closed-boundary systems are explored to investigate the technical limits of storage capacity of subsurface porous media, as required for the CO2-mitigation technology of carbon capture and storage (CCS). In particular; the effects of reservoir characteristics as well as the nature and mix of fluids that originally saturate the porous media are elucidated. An improved analytic method, premised on the concept of in-situ fluid displacement and replacement, of estimating the storage capacity of open systems is proposed and evaluated. For closed systems, our analyses show that the general order of attractiveness (technical storage capacity) of potential sites is aquifer < water-depleted oil < undepleted oil < gas-depleted oil < depleted gas < undepleted gas formations. However, owing to the complexity of microscopic and macroscopic events, similar simple conclusion can not be drawn on the relative attractiveness of various open-boundary sinks. As a case study, we examine the applicability of CCS in Nigeria. From first-order estimates of the pore volumes and other reservoir-fluid properties in Nigeria, we quantify the limits and time-scale of "available" geologic sinks to accommodate current and future loads of anthropogenic CO2 emissions from the Nigerian fossil-fired power sources. Due to the relatively poor storage capacity of the potential sites compared to the anticipated CO2 load from power plants, which is just one of the CO2 sources, sequestration into underground formations may not, on its own, be a sustainable technical solution for Nigeria. Additionally, for the open systems, which define the upper limits of storage capacity, the potential challenges of managing displaced formation brine (and other less valuable fluids) may be overwhelming. As a complement, we offer some potential outlets for CO2 generated from these captive and other sources. Finally, long-term carbon-mitigation strategies hinged on mixed solutions are enumerated.
- North America > United States (1.00)
- Africa > Nigeria (1.00)
- Europe (0.93)
- Oceania > Australia > Western Australia (0.28)
- Geology > Rock Type > Sedimentary Rock (0.67)
- Geology > Petroleum Play Type (0.47)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.67)
- Oceania > Australia > Western Australia > Western Australia > Timor Sea > Browse Basin (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Timor Sea > Browse Basin (0.99)
- Africa > Nigeria > Niger Delta > Niger Delta Basin (0.99)
Pseudo-components for Nigerian Heavy Oil and Bitumen
Lawal, Kazeem A. (Shell Nigeria Exploration & Production Company) | Adenuga, Ademola O. (Shell Petroleum Development Company, Nigeria)
Abstract In composition and behaviour, bitumen and heavy oil are more complex than conventional oil; hence they pose greater challenges for reservoir and process simulations. This notwithstanding, one practical approach for constructing efficient fluid-property models is the lumping technique, entailing the use of pseudo-components (PC). However, this is not so straight-forward, especially for these unconventional hydrocarbons whose compositions are typically available as chemical aggregates (saturates, aromatics, resins and asphaltenes) rather than the common and more convenient pure components. This paper highlights key issues affecting construction of PC’s in general, and limits them to heavy oil and bitumen. It argues that the number and characters of PC’s should be influenced by prospective method of development, processing as well as the nature of fluids the crude would contact. Hence, process-based PC schemes are proposed for the Nigerian unconventional crudes. As an example, the number of components required for a thermal process using asphaltene-precipitating injectant (e.g. CO2) and that of a process based on steam, a non-precipitant, is shown to differ. Similar distinctions are indicated between thermal and solvent-based processes. For some reference conditions, it is demonstrated that the Nigerian heavy crude can, in its simplest form, be reasonably represented as a single-component and up to five components where it is likely to undergo more complex processes or when greater details are necessary. With minor modifications, the proposed schemes should be adaptable to heavy crudes elsewhere.
- Africa > Nigeria (1.00)
- North America (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.71)
Preliminary Assessment of Oil-Rim Reservoirs: A Review of Current Practices and Formulation of New Concepts
Lawal, Kazeem A. (Shell Nigeria Exploration & Production Company) | Wells, Inewari A. (Shell UK Exploration & Production) | Adenuga, Ademola O. (Shell Petroleum Development Company, Nigeria)
Abstract Where oil is the primary target, undesirable production of gas and water complicates the exploitation, management and performance evaluation of thin oil reservoirs. Conventionally, either as a precursor or benchmarking tool for relatively expensive simulation studies, zero-dimensional first-pass models are employed to evaluate performance. This paper reviews some common models for conducting preliminary assessment of oil-rim reservoirs. The models, diverse in underlying concepts and functional forms, are Osoro et al. (2005), Wyne et al. (2005), Kabir et al. (2004), Vo et al. (2004), and Irrgang (1994). By highlighting their relative strengths and weaknesses, they are shown to be generally inconsistent, inherently limited in scope of applicability, and could yield non-physical results. Consequently, they are not robust as screening and validation tools. The main explanation for the non-robustness of these empirical and simulation-based correlations is that they do not capture the key physics of oil-rim reservoirs. Hence, a different approach is imperative. In sharp departure from current practices, an integrated energy-balance approach is introduced. In principle, the energy potential of the reservoir establishes the upper bounds of hydrocarbon recovery. For a system under gas-cap drive, an expression for the theoretical limits of reservoir energy is derived, showing that the primary controls of reservoir potential are initial reservoir pressure and volume of gas-cap. Further developments of the proposed concept would focus on deriving expressions for the demand-side of the energy balance.
- Africa > Nigeria (0.94)
- Asia (0.94)
- North America (0.68)
- Oceania > Australia > Victoria > Bass Strait > Gippsland Basin > Central Deep Basin > Bream Field (0.99)
- Asia > Indonesia > Kalimantan > Serang Field (0.99)
- Africa > Nigeria > Gulf of Guinea > Rivers > Niger Delta > Niger Delta Basin > OML 23 > Soku Field (0.99)
Probabilistic Inversion of Complex Channelised Reservoirs in Deep Water Niger Delta
Fehintola, Tope (Shell Nigeria Exploration & Production Company ) | Al-Mandhary, Inayat (Shell Nigeria Exploration & Production Company) | Weaver, Sidney (Shell Nigeria Exploration & Production Company)
Abstract In this paper, we will discuss the probabilistic seismic inversion of Bonga main reservoirs, with the objective of updating the reservoir static models with the net sand prediction from seismic. A unique solution to the seismic inverse problem does not exist. Uncertainties arise from two sources: noise in the seismic data and ambiguities in the inverse problem itself. Ambiguities are mainly caused by the fact that the seismic data are band limited. Most inversion algorithms, often guided by well and horizon constraints, typically produce a single solution. This solution may represent the most likely subsurface model but it does not give information about other possible solutions. For the results discussed in this paper, we used a trace-by-trace based inversion that relies upon rock and fluid property relationships that describe acoustic properties (Vp, Vs, density) as a function of reservoir properties (e.g. porosity, net-to-gross etc). A prior model is provided as input. This prior model is the initial reservoir static model from which the rock and fluid properties are obtained. These properties are then perturbed in a statistical manner for a number of iterations, deriving acoustic impedances which are used to generate the corresponding synthetic traces. These synthetic traces are then compared with the actual seismic response, and selected against a matching criterion such as semblance. The probabilistic approach combines the seismic modelling with a statistically correct examination of uncertainties taking into account noise in the seismic data. As no well is used to constrain the inversion, this allows for blind well information to be used as validation points for the inversion results. This procedure, in addition to providing the "most likely" model, also provides a statistical examination of uncertainties. Introduction Shell Nigeria Exploration and Production Company is currently using a Shell proprietary application to run probabilistic seismic inversion on the Bonga main reservoirs, with the objective of updating the static models with the net sand prediction from seismic. Probabilistic seismic inversion fully accounts for uncertainties in reservoir properties and noise in the seismic data, such that the inherent uncertainties are captured in the net sand predicted. By constraining the derivation of the net sand with the seismic data, we will have statistically appropriate estimates of the correctness of the input static model.
The Error Function and its Complement: A Comparison of Some Approximate Models
Lawal, Kazeem A. (Shell Nigeria Exploration & Production Company)
Abstract Applying the conservation laws to the transient transport problems of most processes, including diffusion, heat and momentum transfer, normally yield parabolic partial differential equations which solutions, for semi-infinite systems, usually include either the error function or the complementary error function. While tabulated values are available for real arguments of these functions, the need for look-up tables and interpolations makes them computationally intensive for implementation in computer programs and other applications. Although ‘simple’ models have been fitted to these values, it is imperative that such models preserve the key properties of these functions. Combining the criteria of accuracy, differentiability, and integrability with mathematical consistency, this paper examines the approximate models of Kalkaja (2009), Winitzki (2008), van Halen (1989) and Greene (1989), premised on different assumptions and of varied forms and mathematical elegance. In terms of accuracy, the van Halen (1989) model is the most reliable, successively trailed by Winitzki (2008), Kalkaja (2009), and Greene (1989) models. Despite being the most accurate, the van Halen (1989) model is the most complex and computationally expensive. Although they are all continuous and differentiable, obtaining their derivatives analytically, involves varying complexities, with van Halen (1989) most demanding and Greene (1989), the least intensive. With current knowledge, none of the models is amenable to analytic (direct) integration. Considering all performance indices, while the Winitzki model is the most consistent, van Halen approximation is the least consistent. In conclusion, whereas the accuracies of these approximate models are satisfactory for most engineering applications, their robustness to mathematical (analytic) operations is not convincing. Although there is scope for improvement, it is recommended that greater efforts be directed at the development of theoretically rigorous models, which ironically, may not necessarily be more complex. Typical applications of this work include analysis of reservoirs under thermal or miscible floods.
Key Elements of Successful Well and Reservoir Management in the Bonga Field, Deepwater Nigeria
Sathyamoorthy, S. (Shell Nigeria Exploration & Production Company ) | Olatunbosun, O. (Shell Nigeria Exploration & Production Company) | Sabatini, D. (Shell Nigeria Exploration & Production Company) | Orekyeh, U. (Shell Nigeria Exploration & Production Company) | Olaniyan, E. (Shell Nigeria Exploration & Production Company)
Abstract Production from the deepwater Bonga turbidite reservoirs was started in November 2005. As with all waterflood and Enhanced Oil Recovery schemes, ‘world-class’ Well and Reservoir Management (WRM) is the foundation of a successful project. A comprehensive WRM plan was defined for Bonga very early in the project, and its implementation from start-up has demonstrated tremendous value. More than 220 MMstb have been produced as of March 2009 from 13 subsea producers, and reservoir pressures have been maintained by water injection from the start of production in 13 subsea high rate water injectors, allowing high field production rates to be sustained. Well and reservoir performance data obtained during the first three years of production, and information from 4 D seismic shot in early 2008 are now used to optimize the planning and drilling of additional wells as part of the Phase 2 development drilling project. Bonga is a ‘brownfield’ that is not immune to normal well and asset integrity issues, and declines in well injectivity and productivity. Ability to respond swiftly to these issues is part of the Bonga WRM Plan. This paper presents key elements of successful WRM in Bonga. These include people factor and cross discipline integration, Smart Fields® capability, ‘live’ WRM Plan and monitoring, good understanding of subsurface, application of integrated production modelling, intervention readiness and effective well integrity management. The paper concludes on key learnings applicable to future deepwater waterflood projects. Introduction Bonga Main, located in OML118 offshore Nigeria (Figure 1), is the first major deepwater field 1 operated by Shell in West Africa in partnership with ExxonMobil, Total and Agip, and under Production Sharing Contract with NAPIMS. Water depths at Bonga ranges from 3100 to 3800 ft. The Lower to Upper Miocene Bonga reservoirs are interpreted as stratigraphically / structurally trapped mud rich unconfined turbidite systems in a mid-lower slope setting. Sediments were deposited during major sea level low stands where submarine fans were supplied with coarse clastics via the major slope canyon systems. The predominantly channelized reservoirs are comprised of fine-grained amalgamated channel sands, massive sands and overbank deposits. The development of the Bonga field was based on five stacked reservoirs (690, 702, 710/740, 740SE and 803) between 6,000 and 10,500 ftss covering over 60 km. These reservoirs are generally less than 100 ft thick, and measured sand porosities, ranging from 25 to 35%, are associated with multi-Darcy permeabilities.
- Geophysics > Seismic Surveying (0.69)
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.50)
- South America > Brazil > Campos Basin (0.99)
- Asia > Malaysia > Terengganu > South China Sea > Malay Basin > Guntong Field (0.99)
- Africa > Nigeria > Gulf of Guinea > Niger Delta > Niger Delta Basin > OML 118 > Bonga Field (0.99)
- North America > United States > Arkansas > Smart Field (0.98)