Imperial College London

Dr Craig Smalley

Faculty of EngineeringDepartment of Earth Science & Engineering

Visiting Professor
 
 
 
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c.smalley

 
 
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Royal School of MinesSouth Kensington Campus

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Summary

 

Publications

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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

JOURNAL ARTICLE

Smalley PC, Muggeridge AH, Dalland M, Helvig OS, Høgnesen EJ, Hetland M, Østhus Aet al., 2018, Screening for EOR and estimating potential incremental oil recovery on the Norwegian Continental Shelf

© 2018, Society of Petroleum Engineers. This paper presents an improved approach for rapid screening of candidate fields for EOR and estimation of the associated incremental oil recovery, and the results of applying it systematically to oil fields on the Norwegian Continental Shelf (NCS), an area that already has a high average recovery factor (47%). Identifying, piloting and implementing new improved recovery methods within a reasonable time is important if substantial remaining oil volumes on the NCS are not to be left behind. The approach uses up-to-date screening criteria, and has more sophisticated routines for calculating screening scores and incremental oil recovery compared to previous published methods. The EOR processes screened for are: hydrocarbon miscible and immiscible WAG, CO2 miscible and immiscible WAG, alkaline, polymer, surfactant, surfactant/polymer, low salinity, low salinity/polymer, thermally activated polymers and conventional near well gel treatments. Overall screening scores are derived from sliding-scale scores for individual screening criteria, weighted for importance, and with the ability to define non-zero scores when non-critical criteria are outside their desired range, so avoiding the problem of processes being ruled out completely even though rock or fluid properties are only marginally outside the threshold of applicability. Incremental recoveries are estimated taking into account the existing recovery processes in the field and are capped by theoretical maximum recovery factors derived from theoretical/laboratory values for displacement and sweep. The methodology calculates the expected increment (and uncertainty range) for each EOR process and the increments for the top three compatible process combinations. The methodology was implemented in a spreadsheet-based tool that allowed multiple fields to be screened and the results compared and evaluated. The new tool was used to estimate the potential EOR opportunity for 53 reser

CONFERENCE PAPER

Smalley PC, 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

JOURNAL ARTICLE

Huq F, Smalley PC, Morkverd PT, Johansen I, Yarushina V, Johansen Het 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

JOURNAL ARTICLE

Lumsden PJ, Smalley PC, Hallam R, Salino PA, Wells SJ, Primmer TJet 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.

CONFERENCE PAPER

Go J, Bortone I, Muggeridge A, Smalley Cet al., 2014, Predicting Vertical Flow Barriers Using Tracer Diffusion in Partially Saturated, Layered Porous Media, TRANSPORT IN POROUS MEDIA, Vol: 105, Pages: 255-276, ISSN: 0169-3913

JOURNAL ARTICLE

Dale A, John CM, Mozley PS, Smalley PC, Muggeridge AHet 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

JOURNAL ARTICLE

Go J, Smalley PC, Muggeridge A, 2012, Appraisal of reservoir compartmentalization using fluid mixing time-scales: Horn Mountain Field, Gulf of Mexico, PETROLEUM GEOSCIENCE, Vol: 18, Pages: 305-314, ISSN: 1354-0793

JOURNAL ARTICLE

Sathar S, Worden RH, Faulkner DR, Smalley PCet 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

JOURNAL ARTICLE

Houston S, Smalley C, Laycock A, Yardley BWDet 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

JOURNAL ARTICLE

, 2010, Reservoir compartmentalization: Get it before it gets you, Pages: 25-41, ISSN: 0305-8719

This paper examines the impact of compartmentalization on oil recovery, the importance of identifying it during field appraisal, and methods to evaluate it using fluid data. The impact on recovery factor is highlighted using a global database of oil field recovery factors as a function of reservoir complexity and compartmentalization, and emphasized in two case studies. The effect of compartmentalization on oil recovery demonstrates the benefit in characterizing compartmentalization correctly during appraisal, so that the field can be developed in an optimal manner. Early characterization of field compartmentalization requires making maximum use of available fluid data during appraisal. When interpretingfluid data to identify compartmentalization, it is critical to take into account the different time-scales for various fluid signals (pressure, contacts, density, composition) to equilibrate, and to be able to extrapolate to field production time-scales. This is essential to avoid false negatives (compartments assumed absent due to homogeneous fluid properties, when in fact fluids would have equilibrated even in the presence of compartments), false positives (where fluid differences are interpreted as evidence of compartments when in fact there has not been sufficient time for equilibration to occur), and to resolve apparently conflicting data (some fluid indicators are at equilibrium, others are not). Rigorous simulation of fluid equilibration is a complex multiphase multidimensional process, and is generally reserved for specialist in-depth studies. However, order-of-magnitude evaluations can be made using analytical solutions in minutes, allowing many 'what-if' scenarios to be considered and uncertainty to be assessed. Analytical solutions for estimating the time required for spatially-varying fluid properties to revert to steady state distributions are reviewed. All these mixing processes are shown to be diffusive in character. An effective diffusion coefficient

CONFERENCE PAPER

Smalley PC, Ross B, Brown CE, Moulds TP, Smith MJet 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

JOURNAL ARTICLE

, 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: 9781444304510

© 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.

BOOK CHAPTER

, 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

CONFERENCE PAPER

Smalley PC, Begg SH, Naylor M, Johnsen S, Godi Aet al., 2008, Handling risk and uncertainty in petroleum exploration and asset management: An overview, AAPG BULLETIN, Vol: 92, Pages: 1251-1261, ISSN: 0149-1423

JOURNAL ARTICLE

Houston SJ, Yardley BWD, Smalley PC, Collins Iet al., 2007, Rapid fluid-rock interaction in oilfield reservoirs, GEOLOGY, Vol: 35, Pages: 1143-1146, ISSN: 0091-7613

JOURNAL ARTICLE

, 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

CONFERENCE PAPER

Smalley PC, Collins I, 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

CONFERENCE PAPER

Haddad SC, Worden RH, Prior DJ, Smalley PCet 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

JOURNAL ARTICLE

Muggeridge A, Abacioglu Y, England W, Smalley Cet al., 2005, The rate of pressure dissipation from abnormally pressured compartments, AAPG BULLETIN, Vol: 89, Pages: 61-80, ISSN: 0149-1423

JOURNAL ARTICLE

, 2004, Rates of reservoir fluid mixing: Implications for interpretation of fluid data, Pages: 99-113

This paper highlights the benefits of using knowledge of the rates of fluid mixing in the interpretation of reservoir fluid data. Comparison of the time it would take for a fluid difference to mix with the actual time available for mixing to occur allows two significant advances over a purely statistical analysis of reservoir fluid data: (1) differentiation of a step in fluid properties, indicative of a barrier to fluid communication, from a gradient indicative of incomplete mixing; and (2) quantitative estimation of the degree of compartmentalization that can readily be adapted into models for prediction of reservoir production performance. We review the existing equations that estimate the mixing times for three main types of variation in fluid properties (fluid contacts, fluid density and fluid chemistry). In addition, a new relationship for fluid pressure mixing is presented. In each case the relationships were validated by comparison with numerical simulation. The different fluid mixing processes were compared by applying the equations to a range of simple fluid scenarios in one simple reservoir description. This shows that mixing times for fluid mixing processes are diffusion > fluid density > fluid contacts > fluid pressure. For each scenario, the processes were analysed in terms of the volume of fluid that must move in order to bring the system to equilibrium and the drive for fluid mixing (pressure difference x permeability/viscosity). Perhaps surprisingly, there is an excellent linear relation between fluid mixing times (a) calculated from the mixing equations and (b) estimated from volume/drive. This indicates that fluid volumes and mixing drive are the main controls on fluid mixing times. This can be used to derive simple interpretation guidelines to estimate mixing rates even in the absence of quantitative modelling. A simple field case study demonstrates how this understanding of fluid mixing times can add value to the interpretation of reserv

BOOK CHAPTER

Muggeridge A, Abacioglu Y, England W, Smalley Cet al., 2004, Dissipation of anomalous pressures in the subsurface, JOURNAL OF GEOPHYSICAL RESEARCH-SOLID EARTH, Vol: 109, ISSN: 2169-9313

JOURNAL ARTICLE

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

CONFERENCE PAPER

Marchand AME, Smalley PC, Haszeldine RS, Fallick AEet 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

JOURNAL ARTICLE

Marchand AME, Haszeldine RS, Smalley PC, Macaulay CI, Fallick AEet al., 2001, Evidence for reduced quartz-cementation rates in oil-filled sandstones, GEOLOGY, Vol: 29, Pages: 915-918, ISSN: 0091-7613

JOURNAL ARTICLE

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

JOURNAL ARTICLE

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

JOURNAL ARTICLE

Smalley PC, Goodwin NS, Dillon JF, Bidinger CR, Drozd RJet al., 1997, New tools target oil-quality sweetspots in viscous-oil accumulations, SPE RESERVOIR ENGINEERING, Vol: 12, Pages: 157-161, ISSN: 0885-9248

JOURNAL ARTICLE

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.

JOURNAL ARTICLE

Worden RH, Smalley PC, Fallick AE, 1997, Sulfur cycle in buried evaporites, GEOLOGY, Vol: 25, Pages: 643-646, ISSN: 0091-7613

JOURNAL ARTICLE

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