86 results found
Smalley PC, Walker CD, Belvedere PG, 2018, A practical approach for applying Bayesian logic to determine the probabilities of subsurface scenarios: Example from an offshore oilfield, AAPG BULLETIN, Vol: 102, Pages: 429-445, ISSN: 0149-1423
Muggeridge AH, Smalley PCC, Dalland M, et al., Screening for EOR and Estimating Potential Incremental Oil Recovery on the Norwegian Continental Shelf, SPE Improved Oil Recovery Conference
Smalley C, Chebotar K, 2017, Event-based risk management for subsurface risks: An approach to protect value generation from oil and gas fields, AAPG Bulletin, Vol: 101, Pages: 1473-1486, ISSN: 0149-1423
Event-based risk management (EBRM) is an improved way of describing subsurface uncertainties and their possible business impacts in a manner that facilitates specific actions to improve business performance. In EBRM, uncertainties are viewed as potential causes of risk events that could in turn lead to consequences that affect the attainment of objectives.This “causes-event-consequences” syntax aids the design of prevention measures to inhibit the causes turning into the event, mitigation measures to reduce the potential consequences should the risk event occur, and also facilitates construction of a risk taxonomy scheme based on risk consequences, events and causes. Using a dataset of 1456 subsurface risks, each risk was described in this manner, placed in the taxonomy and the proportion of risks in each taxonomic group analysed. This revealed clear trends in the relative frequency of risk groups with type of field: for example, risks related to hydrocarbon in-place volumes are more frequently identified in deep-water oilfields and gas fields feeding liquefied natural gas plants, situations in which resource volumes are critical to support the large project capital costs. Trends were also evident withfield maturity: for example, risks related to hydrocarbon in-place volumes are more frequently identified before the field sanction decision than afterwards.
Huq F, Smalley PC, Moerkved PT, et al., 2017, The Longyearbyen CO2 Lab: Fluid communication in reservoir and caprock, International Journal of Greenhouse Gas Control, Vol: 63, Pages: 59-76, ISSN: 1750-5836
The Longyearbyen CO2 Lab of Svalbard, Norway was established to estimate the potential for geological carbon sequestration at Spitsbergen. Several monitoring wells were drilled in and around the planned CO2 injection site. These revealed a Triassic to Cretaceous stratigraphy consisting of (from top to bottom) a zone of permafrost, the aquifer, the caprock shale, and the upper, middle and lower reservoir. This paper uses two tools to investigate fluid communication within and between these entities: 87Sr/86Sr of formation waters extracted from cores using the residual salt analysis (RSA) method, and the δ13C of gases, principally methane and CO2, degassed from core samples.The Sr RSA data reveal that the upper reservoir rocks have very constant formation water 87Sr/86Sr (0.7130) in wells several kilometres apart, suggesting good lateral communication on a geological timescale. However, there is a distinct barrier to vertical communication within the middle reservoir, indicated by a step change in 87Sr/86Sr (0.7130–0.7112), corresponding to thin but presumably laterally extensive (>1.5 km) lagoonal mudrocks. The aquifer, which shows a gradient in 87Sr/86Sr, is also interpreted to have some degree of vertical internal communication on a geological time scale. The caprock shale shows large-scale (over 350 m) smooth vertical gradient in 87Sr/86Sr (0.7200-0.7130). This is indicative of an ongoing mixing process between high- 87Sr/86Sr waters within the caprock and lower- 87Sr/86Sr waters in the underlying reservoir. Diffusion and flow modelling of the Sr data suggest that at some time in the past, shale fluid transport properties were enhanced by the formation of temporary pressure escape features (fractures or chimneys) during deep burial and uplift, or cycles of glaciation. Nevertheless, the smooth compositional gradient in the caprock indicates that fluid mixing has subsequently taken place slowly, dominated by diffusion. This interpretation is supported
Alane A, Lumsden PJ, Smalley PC, et al., 2015, The reservoir technical limits approach applied to maximising recovery from volumetric and aquifer-drive gas fields, Pages: 3894-3911
© Copyright 2015, Society of Petroleum Engineers. Maximising recovery of hydrocarbons from oil and gas fields represents responsible asset management and is extremely valuable both to the operator and the host country. Doing this successfully involves a complex combination of technical, commercial, organizational and human factors. This was addressed by developing the Reservoir Technical Limits (RTL™) process; the process and its application to oil fields was described in a 2009 SPE paper (109555). The present paper describes subsequent progress in developing RTL™, including a description of a new gas efficiency factor framework for use in volumetric and aquifer-drive reservoirs.
Dale A, John CM, Mozley PS, et al., 2014, Time-capsule concretions: Unlocking burial diagenetic processes in the Mancos Shale using carbonate clumped isotopes, EARTH AND PLANETARY SCIENCE LETTERS, Vol: 394, Pages: 30-37, ISSN: 0012-821X
Go J, Bortone I, Smalley PC, et al., 2014, Predicting Vertical Flow Barriers Using Tracer Diffusion in Partially Saturated, Layered Porous Media, Transport in Porous Media
Sathar S, Worden RH, Faulkner DR, et al., 2012, THE EFFECT OF OIL SATURATION ON THE MECHANISM OF COMPACTION IN GRANULAR MATERIALS: HIGHER OIL SATURATIONS LEAD TO MORE GRAIN FRACTURING AND LESS PRESSURE SOLUTION, JOURNAL OF SEDIMENTARY RESEARCH, Vol: 82, Pages: 571-584, ISSN: 1527-1404
Go J, Smalley PC, Muggeridge A, 2012, Using reservoir mixing to evaluate reservoir compartmentalization from appraisal data – validation using data from the Horn Mountain field, Gulf of Mexico, Petroleum Geoscience, Vol: 18, Pages: 305-314
Houston S, Smalley C, Laycock A, et al., 2011, The relative importance of buffering and brine inputs in controlling the abundance of Na and Ca in sedimentary formation waters, MARINE AND PETROLEUM GEOLOGY, Vol: 28, Pages: 1242-1251, ISSN: 0264-8172
Smalley C, Muggeridge A, 2008, Reservoir Compartmentalization: Get it before it gets you, Geological Society Conference on Reservoir Compartmentalization
Smalley PC, Ross B, Brown CE, et al., 2009, Reservoir Technical Limits: A Framework for Maximizing Recovery From Oil Fields, SPE RESERVOIR EVALUATION & ENGINEERING, Vol: 12, Pages: 610-617, ISSN: 1094-6470
Emery D, Dickson JAD, Smalley PC, 2009, The Strontium Isotopic Composition and Origin of Burial Cements in the Lincolnshire Limestone (Bajocian) of Central Lincolnshire, England, Carbonate Diagenesis, Pages: 271-271, ISBN: 9780632029389
© 1990 The International Association of Sedimentologists. All Rights Reserved. Strontium isotopic composition (87Sr/86Sr) of two petrographically, chemically and isotopically (δ18O and (δ13C) distinct phases of burial calcites from the Lincolnshire Limestone are indistinguishable (0-70820 ± 26). The mean87Sr/86Sr ratio of these phases is considerably more radiogenic than87Sr/86Sr ratios of Bajocian marine waters (~ 0-70725). Neither Bajocian marine waters nor meteoric waters buffered by host marine carbonate in the Limestone could have precipitated the burial spars. Radiogenic strontium may have been contributed from K-feldspar dissolution and/or clay recrystallization, either within clastic portions of the Limestone itself, or from major clastic units adjacent to the Limestone. Alternatively, Palaeozoic marine waters or remobilized Palaeozoic marine carbonate and/or sulphate could have supplied the necessary radiogenic strontium.
Muggeridge AH, Smalley PC, 2008, A diagnostic toolkit to detect compartmentalization using time-scales for reservoir mixing, Pages: 1699-1709
Unidentified reservoir compartmentalization through faulting or depositional heterogeneity can have a profound, usually adverse, effect on oil or gas recovery. Thus it is vital to characterize reservoir compartmentalization as early as possible in field life, ideally during appraisal. One signature of compartmentalization is the detection of variable fluid properties (e.g. pressure, fluid contacts, oil or water composition) in different parts of the reservoir. Such spatial variations arise during the burial, structural and filling history of the reservoir, and gradually equilibrate through time. However such spatial variations may persist simply because sufficient time has not yet elapsed for that property to equilibrate, potentially leading to false-positive diagnoses (variations are present but relate to insufficient mixing times, not compartmentalization). In other cases, mixing can occur so rapidly that fluid variations have already mixed, leading to potential false-negative diagnoses (variations not present because mixing has occurred quickly in spite of compartmentalization that will affect the production timescale). It is thus vital to incorporate an understanding of reservoir mixing timescales into the early diagnosis of compartmentalization. This paper provides simple analytic expressions for estimating the time taken for tilted contacts and spatial pressure or compositional variations to return to their equilibrium distribution, as a function of reservoir thickness, length, porosity, permeability, fluid viscosity, density and compressibility. These form a simple and practical diagnostic toolkit. Use of this toolkit reveals many cases where lateral compositional variations do not indicate compartmentalization but result from incomplete mixing due to very slow molecular diffusion. In contrast, pressure may equilibrate across a micro-Darcy, permeability fault in 100,000 years, so uniform pressure does not necessarily guarantee good reservoir communication on
Smalley PC, Begg SH, Naylor M, et al., 2008, Handling risk and uncertainty in petroleum exploration and asset management: An overview, AAPG BULLETIN, Vol: 92, Pages: 1251-1261, ISSN: 0149-1423
Houston SJ, Yardley BWD, Smalley PC, et al., 2007, Rapid fluid-rock interaction in oilfield reservoirs, GEOLOGY, Vol: 35, Pages: 1143-1146, ISSN: 0091-7613
Smalley PC, Ross B, Brown CE, et al., 2007, Reservoir technical limits: A framework for maximizing recovery from oil fields, Pages: 540-549
Maximizing recovery is an important part of responsible asset management and of optimizing value from an incumbent resource position. BP's Reservoir Technical Limits (RTL™) process has proved highly effective at estimating oilfield maximum recovery potential and identifying/prioritizing specific activities to help deliver it. This paper describes the process and examples of how it has worked and can be applied. RTL incorporates a conceptual framework with supporting software, designed to stimulate and structure a conversation with the asset team in a workshop environment. Key ingredients are: in-depth knowledge/experience of the cross-disciplinary asset team; trained facilitation; cross-fertilization from external technical experts; a toolkit to encourage innovation in a structured and reproducible manner. The RTL framework represents recovery factor as the product of four efficiency factors: Pore-Scale Displacement (microscopic efficiency of the recovery process); Drainage (connectedness to a producer); Sweep (movement of oil to producers within the drained volume); Cut-offs (losses related to end of field life/access). Increasing recovery involves trying to increase all of these efficiency factors. RTL builds upon the opportunity set already contained in the Depletion Plan. New opportunities are identified systematically by comparing current/expected efficiency values with data from high-performing analogue fields, seeding ideas with checklists of previously successful pre-screened activities. The identified opportunities are prioritized based on size, cost, risk, timing and technology stretch, and then validated by recovery factor benchmarking: (a) internally, comparing bottom-up (summing opportunity volumes) and top-down (from efficiencies) values; and (b) externally, by comparison with analogue fields.The result is a prioritized list of validated opportunities and an understanding of how each activity affects the reservoir to increase recovery. The activi
Houston SJ, Yardley BWD, Smalley PC, et al., 2006, Precipitation and dissolution of minerals durina waterfloodina of a North Sea Oil Field, Pages: 300-308
A long-term study of produced water chemistry from a North Sea field was used to investigate the mechanisms of water mixing and water-rock interaction in the reservoir. Seawater flooding has continued throughout much of the production life. Detailed repeated sampling of the produced water was undertaken and has produced an extensive dataset, yielding information on water chemistry variations in space and time. The dataset documents both fluid mixing in the field and the physical, chemical and thermodynamic response of the system to the injection of seawater. Analysis of the data establishes the nature of the controls on the composition of the scale-prone formation water, and enables an in-depth look at the fluid-rock interactions occurring in the reservoir during a waterflood. Changes in produced-water chloride concentration through time reflect changing proportions of injected seawater and formation-water, revealing differing patterns of injected-water breakthrough over the field. However, parallel changes in the concentrations of less conservative fluid components provide evidence of fluid-mineral interactions that occurred in the reservoir on the timescale of the waterflood. For example, calcium is enriched in the produced fluid relative to a linear mixture of original formation-water and seawater, while magnesium is depleted, probably reflecting dolomitisation of calcite and growth of clay. Barium and sulphate are strongly depleted due to precipitation of barite. However, mass balance highlights an additional sink for sulphate, possibly reduction to sulphide. Excess silica present in the produced fluid is ascribed to dissolution of silicate phases in the reservoir. Concentrations demonstrate that the produced water is always close to quartz saturation at reservoir temperature, irrespective of the proportion of seawater produced.Analysis of produced water chemistry provides insights into the inner workings of the reservoir system during a waterflood. Study of ind
Haddad SC, Worden RH, Prior DJ, et al., 2006, Quartz cement in the Fontainebleau sandstone, Paris basin, France: Crystallography and implications for mechanisms of cement growth, JOURNAL OF SEDIMENTARY RESEARCH, Vol: 76, Pages: 244-256, ISSN: 1527-1404
Muggeridge A, Abacioglu Y, England W, et al., 2005, The rate of pressure dissipation from abnormally pressured compartments, AAPG BULLETIN, Vol: 89, Pages: 61-80, ISSN: 0149-1423
Muggeridge A, Abacioglu Y, England W, et al., 2004, Dissipation of anomalous pressures in the subsurface, JOURNAL OF GEOPHYSICAL RESEARCH-SOLID EARTH, Vol: 109, ISSN: 2169-9313
Smalley C, England W A, Muggeridge A, et al., 2004, Rates of Reservoir Fluid Mixing: Implications for Interpretation of Fluid Data, Understanding Petroleum Reservoirs: Towards an Integrated Reservoir Engineering, Editors: Cubitt M, England A, Larter R, England, Publisher: Geological Society, ISBN: 9781862391680
Worden RH, Smalley PC, Barclay SA, 2003, H2S and diagenetic pyrite in North Sea sandstones: due to TSR or organic sulphur compound cracking?, GEOFLUIDS IV Meeting, Publisher: ELSEVIER SCIENCE BV, Pages: 487-491, ISSN: 0375-6742
Marchand AME, Smalley PC, Haszeldine RS, et al., 2002, Note on the importance of hydrocarbon fill for reservoir quality prediction in sandstones, AAPG BULLETIN, Vol: 86, Pages: 1561-1571, ISSN: 0149-1423
Marchand AME, Haszeldine RS, Smalley PC, et al., 2001, Evidence for reduced quartz-cementation rates in oil-filled sandstones, GEOLOGY, Vol: 29, Pages: 915-918, ISSN: 0091-7613
Worden RH, Smalley PC, Cross MM, 2000, The influence of rock fabric and mineralogy on thermochemical sulfate reduction: Khuff Formation, Abu Dhabi, JOURNAL OF SEDIMENTARY RESEARCH, Vol: 70, Pages: 1210-1221, ISSN: 1073-130X
Worden RH, Oxtoby NH, Smalley PC, 1998, Can oil emplacement prevent quartz cementation in sandstones?, PETROLEUM GEOSCIENCE, Vol: 4, Pages: 129-137, ISSN: 1354-0793
Smalley PC, Goodwin NS, Dillon JF, et al., 1997, New tools target oil-quality sweetspots in viscous-oil accumulations, SPE RESERVOIR ENGINEERING, Vol: 12, Pages: 157-161, ISSN: 0885-9248
Worden RH, Smalley PC, Fallick AE, 1997, Sulfur cycle in buried evaporites, Geology, Vol: 25, Pages: 643-646, ISSN: 0091-7613
Sulfur isotopes are potent indicators of the way in which sulfur behaves chemically during diagenesis. We have studied sulfur isotope ratios ( 34 S/ 32 S) from a number of minerals and compounds across the Permian-Triassic boundary in the Khuff Formation. Abu Dhabi. The δ 34 S in dissolved marine sulfate increased by 10‰ from the Late Permian to the Early Triassic. Despite precipitation of gypsum from Permian and Triassic seawater and its subsequent dehydration to anhydrite at depths greater than about 1000 m, the primary marine stratigraphic sulfur isotope variation has been preserved in anhydrite in the Khuff Formation. A combination of biostratigraphic and absolute age data show that this 10‰ shift occurred over < 2 m.y. Gypsum dehydration to anhydrite has not involved significant isotopic fractionation or diagenetic redistribution of material in the subsurface. The sulfur isotope variation across the Permian-Triassic boundary is also present in elemental sulfur and H 2 S, at depths greater than 4300 m, formed by reaction of anhydrite with hydrocarbons via thermochemical sulfate reduction. This demonstrates that sulfate reduction has not led to isotope fractionation. It also demonstrates that significant mass transfer has not occurred, at least in the vicinity of the Permian-Triassic boundary, even though elemental sulfur and H 2 S art both fluid phases at depths greater than 4300 m. Thus, despite two major diagenetic processes that converted the sulfur in gypsum into elemental sulfur and H 2 S by 4300 m burial and the potentially mobile nature of some of the reaction products, the primary differences in sulfur isotopes have been preserved in the rocks and fluids. All reactions occurred in situ; there was no significant sulfur isotope fractionation, and only negligible sulfur was added, subtracted, or moved internally within the system.
Worden RH, Smalley PC, Fallick AE, 1997, Sulfur cycle in buried evaporites, GEOLOGY, Vol: 25, Pages: 643-646, ISSN: 0091-7613
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