Publications
97 results found
Smalley C, Muggeridge A, 2022, Reservoir Compartmentalization: Get it before it gets you, Geological Society Conference on Reservoir Compartmentalization
Carlino A, Muggeridge AH, Smalley PC, 2022, Rapid Estimation of Carbon Dioxide Stored in CO2 EOR Operations for Screening Purposes
We describe the development, testing, and first application of a rapid method for estimating the CO2 storage potential associated with CO2 enhanced oil recovery in both secondary and tertiary modes. The new method builds on various published empirical models for predicting incremental oil recovery (and hence CO2storage) in solvent floods. It improves the representation of reservoir heterogeneity caused by de positional layering and fracturing. This is then combined with material balance to make site-specific estimates of theCO2 storage potential. We cross-checked predictions from the new method against historical field data for major onshore CO2floods with satisfactory results considering the very approximate nature of the estimation. We then applied the method to a selection of offshore oil reservoirs and found that, generally, the larger the remaining oil, which is a function of initial size and current recovery factor, the greater the CO2 storage potential. We also modelled the case of continued injection after ceasing oil production at, or after, CO2 break through and observed that, as expected, the amount of CO2 stored at breakthrough depends on how early this occurs, which is affected by reservoir heterogeneity, whereas continued injection is limited by the head room between current reservoir pressure and fracture pressure. The overall storage is the result of the interplay between these two mechanisms. In the studied fields/reservoirs, we demonstrated that large amounts ofCO2 can be stored in terms of absolute mass and that storage of these quantities would represent significant abatement of the emissions generated by burning the incremental oil. The new method can be used as a screening tool to identify and rank candidate oil fields for combinedCO2 enhanced oil recovery and storage in regional, national, or corporate portfolios.
Huq F, Smalley PC, Yarushina V, et al., 2021, Integrated study of water Sr isotopes and carbonate Sr-C-O isotopes reveals long-lived fluid compartments in the Langfjellet oil discovery, Norwegian North Sea, Marine and Petroleum Geology, Vol: 127, Pages: 1-16, ISSN: 0264-8172
Routine measurements of reservoir pressure variation with depth can detect pressure discontinuities indicative of barriers to vertical fluid movement. This study investigates how pressure data can be augmented by detailed profiles of formation water 87Sr/86Sr ratio to determine the precise location and cause of such barriers, and by C–O–Sr isotope analysis of carbonate cements to determine the duration over which the barrier has persisted. The study focuses on the clastic Hugin Formation reservoir in the Langfjellet Oil Discovery (Norwegian North Sea). Here, pressure data indicated a barrier somewhere within a 25 m depth interval. Formation water 87Sr/86Sr was measured with high spatial resolution by extraction from core samples using the residual salt analysis (RSA) method. This revealed three homogeneous populations of water separated by a small step in 87Sr/86Sr over a 7 m interval containing coal and shale layers, and a very large step in 87Sr/86Sr over a 1.2 m interval corresponding to a thin coal and shale layer situated below a major flooding surface. The latter is the main candidate for the pressure barrier. Modelling confirmed that this inferred pressure barrier also greatly retards Sr diffusion.Carbonate cements occur disseminated throughout the reservoir and in several heavily-cemented zones. Oxygen isotope-derived temperatures indicate that these formed in two episodes: (1) Pre-compactional, precipitated shortly after deposition in the zone of bacterial methanogenesis (~30 °C, ~200 m depth, ~162 Ma); (2) Post-compactional incorporating thermal decarboxylation-derived carbon (~90 °C, ~2500 m depth, ~46 Ma). Carbonate 87Sr/86Sr data reveal the same compositional populations present in the current formation water to be present in both cement generations. The water compositional stratification must thus have been present when the early and late cements precipitated, down till today. The persistence of a compositional step for most of the
Julier R, Smalley C, Van Der Molen K, et al., 2021, Integrated brownfield opportunity identification using the efficiency factor approach
The long-term prosperity of oil and gas companies requires a constant influx of new volumes of producible oil and gas that can be developed to replace existing production. Without such activity it is inevitable that production will eventually fall as the resource base is gradually consumed The attractiveness of achieving more barrels from existing discovered fields has always been strong as it has long been recognized that such opportunities can be economically attractive and rapidly brought to fruition. It is also recognized however that such opportunities may be more complex relying both upon excellent subsurface understanding and successful brownfield project execution. It is therefore not surprising that in many cases actual recovery factors (produced volume/initial in-place volume) in oil and gas fields can be significantly less than what should be technically achievable. Identification of economically robust brownfield opportunities remains an industry challenge. In this paper we address this challenge by reporting a new workflow for brownfield opportunity identification leading to recovery factor improvement. Shell's Recovery Factor Improvement (RFI) Workflow was developed to address these issues and builds upon the existing best practice workflows to better explore and define the activities that would be required to achieve top quartile recovery factor performance. The workflow combines elements of various existing published approaches: (1) Shell's TQ-EUR Tool is an internal database that allows current and forecast recovery factor to be compared with that of analogue reservoirs using a reservoir complexity factor and key reservoir performance parameters as comparison criteria across the Shell portfolio. (2) An efficiency factor-based analysis of recovery factor; (3) a structured workshop to elicit new recovery factor improvement activities by addressing each individual efficiency factor in turn; (4) Consistent reporting of results. The combination of these
Smalley PC, Muggeridge AH, Kusuma CR, 2020, Patterns of water 87Sr/86Sr variations in oil-, gas- and water-saturated rocks: Implications for fluid communication processes, distances and timescales, Marine and Petroleum Geology, Vol: 122, Pages: 1-22, ISSN: 0264-8172
This study reviews 87Sr/86Sr depth profiles of formation waters sampled by Sr residual salt analysis (Sr RSA) from >100 oil/gas wells and research sites, including reservoirs with clastic and carbonate host rocks and with gas, oil and water as the continuous fluid phase. Globally, the water data form a smooth trend between low seawater-like 87Sr/86Sr ratios (~0.706) at shallow depths and high (~0.724) ratios in deeply buried rocks, where water-rock interaction dominates.We test the hypothesis that 87Sr/86Sr depth profiles in individual wells could be influenced by diffusional mixing processes by developing 1D diffusion mixing equations to simulate compositional patterns through time and comparing them with observed profiles. Different combinations of boundary and initial conditions generate various patterns characteristic of diffusion, including non-steady-state curves relating to incomplete mixing and steady-state patterns (such as vertical or inclined straight lines) where initial heterogeneities have fully mixed. The dataset yielded 193 occurrences of these patterns. Steady-state patterns are more common and longer in water zones, while non-steady-state patterns are more common and longer in oil and gas zones. The detection of diffusional mixing patterns in hydrocarbon-saturated rocks suggests that diffusion is active, although on average a factor of ~13–18 slower, than in comparable water-saturated rocks.Pattern generation and equilibration times were modelled for each non-steady-state pattern and compared with the time since reservoir filling with oil/gas, revealing that 90% of them could have been generated since filling, but 60% of them would already have mixed to steady state had the initial compositional heterogeneities arisen during or before reservoir filling. This is critical evidence that at least some of the initial heterogeneities must have arisen, and subsequently partially mixed, after filling; these patterns tend to be short (<40 m, usu
Smalley PC, Muggeridge AH, Amundrud SS, et al., 2020, EOR Screening Including Technical, Operational, Environmental and Economic Factors Reveals Practical EOR Potential Offshore on the Norwegian Continental Shelf, Tulsa, Oklahoma, USA, SPE Improved Oil Recovery Conference, Publisher: Society of Petroleum Engineers
Abstract We present a novel advanced EOR screening approach, adding to an existing technical screening toolkit powerful new practical discriminators based on: (1) Operational complexity of converting existing offshore fields to new EOR processes; (2) Environmental acceptability of each EOR process, given current field configuration; (3) Commercial attractiveness and competitiveness. We apply the new approach to 14 EOR processes across 85 reservoirs from 46 oilfields and discoveries on the offshore Norwegian Continental Shelf (NCS). When the operational, environmental and economic thresholds were included, 45% of the technical opportunities were screened out, and the overall potential recovery increment was ~280 MSm3 (million standard cubic metres), the top processes being HC miscible, low salinity/polymer, low salinity, CO2 miscible, gels. Excluding environmental factors (i.e., assuming environmental issues could be solved by new technologies), the increment is ~340 MSm3, indicating a ~60 MSm3 prize for research into environmentally benign EOR methods. The economic thresholds used here were intentionally set low enough to eliminate only severely commercially challenged opportunities; using higher commercially competitive thresholds would reduce the overall volumes by a further ~40 MSm3. The extension of EOR screening to include operational, environmental and economic criteria is not intended as a substitute for in-depth studies of these factors, but it should help stakeholders make earlier and better-informed decisions about selection of individual EOR opportunities for deeper study, leading to piloting and eventual field-scale deployment. Revealing the sensitivity of each EOR process to operational, environmental and economic factors will also help focus R&D onto the practical, as well as technical, barriers to EOR implementation.
Smalley PC, Muggeridge AH, Amundrud SS, et al., 2020, EOR screening including technical, operational, environmental and economic factors reveals practical EOR potential offshore on the norwegian continental shelf
We present a novel advanced EOR screening approach, adding to an existing technical screening toolkit powerful new practical discriminators based on: (1) Operational complexity of converting existing offshore fields to new EOR processes; (2) Environmental acceptability of each EOR process, given current field configuration; (3) Commercial attractiveness and competitiveness. We apply the new approach to 14 EOR processes across 85 reservoirs from 46 oilfields and discoveries on the offshore Norwegian Continental Shelf (NCS). When the operational, environmental and economic thresholds were included, 45% of the technical opportunities were screened out, and the overall potential recovery increment was ~280 MSm3 (million standard cubic metres), the top processes being HC miscible, low salinity/polymer, low salinity, CO2 miscible, gels. Excluding environmental factors (i.e., assuming environmental issues could be solved by new technologies), the increment is ~340 MSm3, indicating a ~60 MSm3 prize for research into environmentally benign EOR methods. The economic thresholds used here were intentionally set low enough to eliminate only severely commercially challenged opportunities; using higher commercially competitive thresholds would reduce the overall volumes by a further ~40 MSm3. The extension of EOR screening to include operational, environmental and economic criteria is not intended as a substitute for in-depth studies of these factors, but it should help stakeholders make earlier and better-informed decisions about selection of individual EOR opportunities for deeper study, leading to piloting and eventual field-scale deployment. Revealing the sensitivity of each EOR process to operational, environmental and economic factors will also help focus R&D onto the practical, as well as technical, barriers to EOR implementation.
Davey R, Smalley C, Sephton M, 2018, A New Approach to Predict Shale Gas Decline Trends in Unconventional Reservoirs Using Molecular Weight Fractionation, 80th EAGE Conference and Exhibition 2018, Publisher: EAGE Publications BV, ISSN: 2214-4609
Muggeridge AH, Smalley PCC, Dalland M, et al., 2018, Screening for EOR and Estimating Potential Incremental Oil Recovery on the Norwegian Continental Shelf, SPE Improved Oil Recovery Conference
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, American Association of Petroleum Geologists (AAPG) Bulletin, Vol: 102, Pages: 429-445, ISSN: 0149-1423
During appraisal of an undeveloped segment of a producing offshore oilfield, three well penetrations revealed unexpected complexity and compartmentalization. Business decisions on whether and how to develop this segment depended on understanding the possible interpretations of the subsurface. This was achieved using the following steps that incorporated a novel practical application of Bayesian logic.1. Scenarios were identified to span the full range of possible subsurface interpretations. This was achieved through a facilitated cross-disciplinary exercise including external participants. The exercise generated 12 widely differing subsurface scenarios, which could be grouped into 4 types of mechanisms: slumping, structural, depositional, and diagenetic.2. Prior probabilities were assigned to each scenario. These probabilities were elicited from the same subsurface team and external experts who performed step 1, using their diverse knowledge and experience.3. The probabilities of each scenario were updated by evaluating them sequentially with 21 individual pieces of evidence, progressively down-weighting belief in scenarios that were inconsistent with the evidence. For each piece of evidence, the likelihood (chance that the scenario could produce the evidence) was estimated qualitatively by the same team using a “traffic-light” high-medium-low assessment. Offline, these were converted to numerical likelihood values. Posterior probabilities were derived by multiplying the priors by the likelihoods and renormalizing to sum to unity across all of the scenarios.4. The most probable scenarios were selected for quantitative reservoir modeling, to evaluate the potential outcomes of business decisions, given each scenario.Of the 12 scenarios identified in step 1, most were strongly down-weighted by the sequential revisions against evidence in step 3; after this, only scenarios in the “slumping” group retained significant posterior probabilities. The
Davey R, Smalley C, Sephton M, 2018, A new approach to predict shale gas decline trends in unconventional reservoirs using molecular weight fractionation
Various aspects of the exploitation of shale reservoirs, whether for hydrocarbon extraction or carbon storage, depend strongly on understanding how the gas is situated at a pore scale within the shale: for example in (isolated) macro-micropores, adsorbed onto the surfaces of pores or absorbed into the matrix of solid shale components. We are testing the hypothesis that gas compositional fractionation during depressurization can be used as a marker for gas stored in these different sites within the shale. This identifies how gas is stored within shales, total gas initially in place (GIP) and location on the estimated ultimate recovery curve (EUR). We created a purpose built sample cell coupled with a GC-FID in order to isolate individual shale constituents and measure molecular weight fractionation between shale gas components from 100% total GIIP to gas depleted. Effects of shale mineralogy on molecular weight fractionation were explored using samples representing key shale constituents as well as “real” shale samples.
Davey R, Smalley C, Sephton M, 2018, A new approach to predict shale gas decline trends in unconventional reservoirs using molecular weight fractionation
© 2018 Society of Petroleum Engineers. All rights reserved. Various aspects of the exploitation of shale reservoirs, whether for hydrocarbon extraction or carbon storage, depend strongly on understanding how the gas is situated at a pore scale within the shale: for example in (isolated) macro-micropores, adsorbed onto the surfaces of pores or absorbed into the matrix of solid shale components. We are testing the hypothesis that gas compositional fractionation during depressurization can be used as a marker for gas stored in these different sites within the shale. This identifies how gas is stored within shales, total gas initially in place (GIP) and location on the estimated ultimate recovery curve (EUR). We created a purpose built sample cell coupled with a GC-FID in order to isolate individual shale constituents and measure molecular weight fractionation between shale gas components from 100% total GIIP to gas depleted. Effects of shale mineralogy on molecular weight fractionation were explored using samples representing key shale constituents as well as “real” shale samples.
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, A technical-limits approach applied to maximizing gasfield recovery, JPT, Journal of Petroleum Technology, Vol: 67, Pages: 66-68, ISSN: 0149-2136
Maximizing recovery of hydrocarbons from oil and gas fields represents responsible asset management and is extremely valuable to both the operator and the host country. Successful pursuit of this goal involves a complex combination of technical, commercial, organizational, and human factors. Reservoir Technical Limits (RTL) system has provided a systematic framework to identify new recovery-improving activities across a portfolio of fields, generate clear ownership of the activities by field teams and individuals, and identify technology requirements (existing or new) to progress the opportunities. The system is used to evaluate the life-of- field recovery potential of oil and gas fields, and the steps required to achieve this potential, on the basis of the key factors including depth of technical knowledge across multiple functions, innovation, creativity, and awareness of latest technologies, and understanding field specificity, so that identified opportunities are properly applicable to the field under review. The system's efficiency-factor framework represents the overall recovery factor for the oil field as a product of four component efficiency factors, pore-scale displacement, drainage, sweep, and cutoffs. ach efficiency factor is given as a fraction between zero and unity and used as a multiplier in the recovery calculation. Once characterized, the base-case recovery factor is bench marked against a screened set of analogs. This identifies whether the recovery factor is high, normal, or low compared with analog fields, giving an idea of the likely potential for recovery-factor improvement.
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
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
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- Citations: 24
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
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- Citations: 17
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
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- Citations: 8
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
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 mean 87Sr/86Sr ratio of these phases is considerably more radiogenic than 87Sr/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.
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
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- Citations: 14
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
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
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- Citations: 16
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
Houston SJ, Yardley BWD, Smalley PC, et al., 2006, Precipitation and Dissolution of Minerals During Waterflooding of a North Sea Oil Field, SPE International Oilfield Scale Symposium, Publisher: SPE
<jats:title>Abstract</jats:title> <jats:p>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.</jats:p> <jats:p>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.</jats:p>
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
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- Citations: 53
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