Thief Zones Research Articles

Oil Recovery From Gas-Over-Bitumen Reservoirs: Results From the AIDROH Pilot Project in Alberta

Summary Producing from bitumen reservoirs overlain by gas caps can be a challenging task. The gas cap acts as a thief zone to the injected steam used during oil-recovery operations and hinders the effectiveness of processes such as steam-assisted gravity drainage (SAGD). Moreover, gas production from the gas cap can accentuate the problem even more by further depressurization of the gas zone. Following a September 2003 ruling by the Alberta Energy Regulator (AER), the oil and gas industry in the province of Alberta, Canada, had approximately 130 million scf/D of sweet gas shut-in to maintain pressure in gas zones in communication with bitumen reservoirs. This decision led to the development of EnCAID (Cenovus' air-injection and -displacement process), a process in which air is injected into a gas-over-bitumen (GOB) zone, and combustion gases are used to displace the remaining formation gas while maintaining the required formation pressure. An EnCAID pilot was started in June 2006, and preliminary results were reported in 2008. After 8 years of operations, the EnCAID project has not only proved to be effective at recovering natural gas and maintaining reservoir pressure, it has also shown it can heat up the bitumen zone and make the oil more mobile and amenable for production. This led to the development of the air-injection and -displacement for recovery with oil horizontal (AIDROH) process. The AIDROH process is the second of two distinct stages. First, an air-injection well is drilled and perforated in the gas cap. The well is ignited and air injection is performed to sustain in-situ combustion in the gas zone. This phase is characterized by a radially expanding combustion front, accompanied by conduction heating into the bitumen below. The second stage begins when horizontal wells are drilled in the bitumen zone. The pressure sink caused by drawing down the wells alters the dynamics of the process and creates a pressure drive for the combustion front to push toward the producers in a top-down fashion, taking advantage of the combustion-front displacement and gravity drainage. In light of the temperature increases observed in the bitumen overlain by the EnCAID project, a horizontal production well was drilled in late 2011 and commenced producing in early 2012. This paper provides an update of the EnCAID pilot results and presents a summary of the technical aspects of the AIDROH project, pilot results, and interpretation of the data gathered to date, such as observation-well temperatures, pre- and post-burn cores, and temperatures along the horizontal producer. Results indicate that the AIDROH process has the potential to maximize oil production from GOB reservoirs, and efforts continue to be made to optimize its design and operation.

Determining the levels and parameters of thief zone based on automatic history matching and fuzzy method

Abstract Thief zone which evolves from long-term water flooding, has become a subject of concern for reservoir engineers, as they lead to early water breakthrough in oil producers and uneven sweep around water injectors, thus it is essential to select wells which need to be modified injection or production profiles. This article presents a methodology of determining the levels and parameters of thief zone in different areas of the reservoir on the concept of “based on the information from every grid of reservoir model” by using automatic history matching and fuzzy method. Since characterizing the reservoir uncertainty is crucial to the reservoir description and future performance predictions, automatic history matching using ensemble Kalman filter (EnKF) with covariance localization is first proposed. Then according to theory of logical analysis (TLA), fuzzy analytic hierarchy process (FAHP) and Fuzzy comprehensive evaluation (FCE) method, the system to quantitative evaluation of thief zone is presented, and the reservoir can be graded into three categories of severe thief zone, light thief zone and no thief zone. The methodology has been applied to X oilfield in western North China which has 17 layers from the top to the bottom in the stratigraphy, and the results show that 5 layers exist severe thief zones and the volume of severe thief zones is the largest in layer 32, and there are four wells in this layer that their injection or production profiles must be modified. In addition, the interwell tracer test result shows the proposed methodology is more accurate by comparing with other methods in the references which mainly rely on the properties of single well to determine the levels of thief zone. The proposed approach is more accurate and less manpower needs to identify thief zones, which also providing a strong basis for oilfield development adjustment in high water cut stage.

Experimental investigation on plugging behavior of granular lost circulation materials in fractured thief zone

ABSTRACTLost circulation of drilling fluid occurs frequently when drilling in fractured formations. Granular lost circulation material (LCM) is still widely used as a cure to combat the circulation loss of drilling fluid. The placement styles of granular LCM in the fractured thief zone are discussed in this paper. A series of experimental tests to examine the placement style have been carried out using a new developed test equipment. The effects of the material type, particle size distribution (PSD), and concentration of the granular LCMs on the plugging behavior have been investigated. The experimental results proved that t the rigid granules work as an ideal bridging material determining the plugging depth, and the powder material is more suitable as filling material controlling the total fluid loss. The PSD of granular LCM dominates the placement style and efficiency in fractured thief zone, and there exists an optimum concentration for maximum effect of granular LCM additives.

Analysis of mixing parameters for polymer gels used for the correction of water injection profiles

Polymer gels as modifiers of the injection profile in secondary recovery processes are a widely used technic in the industry, however, its use is based on the success of their applications, without existing a detailed knowledge of the mechanisms of the phenomenon, leaving open big doubts on design factors, risk variables, prediction of results to be obtained, etc. Design of applications in the field is performed following the concepts formulated since the creation of the technology, involving only fluid-fluid tests, with a qualitative approach that does not allow a detailed analysis of the phenomena. Fluid-fluid tests, commonly used in this technology, are the starting point of this research to further involve quantitative analysis such as ultraviolet rays and rheological tests for better understanding of the process. From this research were obtained new ways to assess mixing parameters needed prior to field application of gels for plugging of water thief zones.

Thief zone identification based on transient pressure analysis: a field case study

Thief zones are generally a channel with high absolute permeability. However, a not very strict theory analysis shows that neglecting the effect of variant of water saturation on formation of thief zone in mature reservoirs cannot explain some thief zones in mature reservoirs. This paper focuses on the effect of water saturation on thief zone development for wells in mature reservoirs with areal permeability heterogeneity. The water saturation increases in high permeable channel with water passing through, which gradually leads to higher value of water phase relative permeability, and thus leads to higher value of effective permeability k·k rw in the high permeable channel than that in surrounding reservoir. The gradually increasing difference of effective permeability k·k rw between permeable channel and surrounding reservoir would be the main reason for formation of thief zones in mature reservoir. The oil–water two-phase numerical model based on PEBI (perpendicular bisection) gridding is used to study effect of variant of water phase saturation on formation of thief zone. We find that relatively small pressure change and not obvious bump in pressure derivative curves during shut-in are indicators of thief zones in mature reservoirs. This finding provides a further understanding for the thief zone development and also gives us a guidance to interpret the buildup pressure data in the mature sandstone reservoirs. A field case study verifies the effectiveness of the new explanation.

CO2 retention values in enhanced oil recovery

Carbon dioxide (CO2) retention is the fraction of the injected volume trapped in the subsurface as a result of enhanced oil recovery (EOR). CO2 retention is determined by multiple factors acting generally in combinations varying according to the geology of the reservoir and the implementation of the recovery. Primarily, the factors are the amount of CO2 remaining in the pore space connected to injection wells but not to the producer; dissolution into the formation water, subjacent aquifer, or both; accumulation in the pore space vacated by produced oil; chemical reaction with the minerals in the matrix; and loss to a thief zone. Accurate modeling of retention is important in the evaluation of the economics of reservoir development and in the assessment of potential CO2 sequestration. This contribution deals with 23 units containing information relating retention rates to the amount of CO2 injected in EOR operations. For all but two units, the flooding is miscible and all but two units are in the United States. Compilation of values reported in the literature shows a tendency for higher values of retention for carbonate than for siliciclastic reservoirs.

Understanding the impact of open-framework conglomerates on water–oil displacements: the Victor interval of the Ivishak Reservoir, Prudhoe Bay Field, Alaska

The Victor Unit of the Ivishak Formation in the Prudhoe Bay Oilfield is characterized by high net-to-gross fluvial sandstones and conglomerates. The highest permeability is found within sets of cross-strata of open-framework conglomerate (OFC). These cross-strata are preserved within unit-bar deposits and assemblages of unit-bar deposits within compound (braid)-bar deposits, and may form thief zones limiting enhanced oil recovery. We incorporate recent research that has quantified important attributes of preserved sedimentary architecture into high-resolution models. Waterflooding experiments using these models demonstrate the control that such architecture has on oil production rate, water breakthrough time, and spatial and temporal distribution of residual oil saturation. We found that when the pressure gradient is orientated perpendicular to the palaeoflow direction, the total oil production and the water breakthrough time are larger, and the remaining oil saturation is smaller, than when it is orientated parallel to palaeoflow. The pressure difference between production and injection wells does not affect sweep efficiency, although the spatial distribution of oil remaining in the reservoir critically depends on this value. Oil sweep efficiency decreases slightly with increase in the proportion of OFC cross-strata. Whether or not clusters of connected OFC span the domain does not visibly affect sweep efficiency.

A laboratory and simulation study of preformed particle gels for water conformance control

Excess water production is a major problem that leads to early well abandonment and unrecoverable hydrocarbon in mature oil fields. Gel treatments at the injection wells to preferentially plug the thief zones are cost-effective methods to improve sweep efficiency in reservoirs and reduce excess water production during hydrocarbon recovery. A recent gel process uses the preformed particle gels (PPGs) to overcome distinct drawbacks inherent in in-situ gelation systems, i.e. lack of control on gelation time, uncertain gelling due to shear degradation, chromatographic fractionation or change of gel compositions, and dilution by formation water.This paper describes the results of PPG injection in both fracture and sandpack models where experimental results were used to develop and validate mechanistic models to design and optimize the flowing gel injection for conformance control processes. Crucial gel properties, such as in-situ rheology and swelling ratio in addition to oil recoveries were investigated. Water and oil permeability reduction factors were measured and modeled as a function of gel rheological properties, rock permeability, and flow rate. The PPG transport models were successfully implemented in a reservoir simulator and validated against the laboratory experiments.

Effects of Reservoir Heterogeneities, Thief Zone, and Fracture Systems on the Fast-SAGD Process

This study presented a numerical investigation for evaluating the potential applicability of Fast-steam-assisted gravity drainage recovery process under complex reservoir conditions, such as shale barriers, thief zones with bottom and/or top water layers, and fracture systems in Clearwater formation. The simulation results indicated that the near well regions are very sensitive with shale layers and only long, continuous shale barriers (larger than 50 m or 25%), which can effect Fast-steam-assisted gravity drainage performance at the above well regions. Besides that, the thief zones have a strongly detrimental effect on Fast-steam-assisted gravity drainage. The results also proved that Fast-steam-assisted gravity drainage recovery process enhanced in the presence of vertical fractures, but horizontal fractures were harmful on the recovery. This article is a worthy guideline for Fast-steam-assisted gravity drainage operations in complex geological reservoirs.

Plugging Agent Type Selecting Methods for Channeling Reservoir

The breakthrough flow of injected water and polymer caused by heterogeneous formation is a serious problem in many oil fields, and the problem has become an important restraint to oil development. The profile control and water shutoff plan is determined by experienced and subjective human judgments, the blocking agent selection and plugging agent dosage are lack of scientific basis. Based on a reservoir engineering study, this article proposes an internal pressure calculation model and an injection pressure calculation model, the ultimate gradient of breakthrough pressure and plugging agent working viscosity. Combining methods of plugging agent performance evaluation method, we conclude the matching relation between characteristic parameter of thief zone and performance of plugging agent. A method for selecting a plugging agent in the light of thief zone is established. Case study results reveal the practicability and effectiveness of this method.

Numerical simulation of fluid-flow processes in a 3D high-resolution carbonate reservoir analogue

A high-resolution three-dimensional (3D) outcrop model of a Jurassic carbonate ramp was used in order to perform a series of detailed and systematic flow simulations. The aim of this study was to test the impact of small- and large-scale geological features on reservoir performance and oil recovery. The digital outcrop model contains a wide range of sedimentological, diagenetic and structural features, including discontinuity surfaces, shoal bodies, mud mounds, oyster bioherms and fractures. Flow simulations are performed for numerical well testing and secondary oil recovery. Numerical well testing enables synthetic but systematic pressure responses to be generated for different geological features observed in the outcrops. This allows us to assess and rank the relative impact of specific geological features on reservoir performance. The outcome documents that, owing to the realistic representation of matrix heterogeneity, most diagenetic and structural features cannot be linked to a unique pressure signature. Instead, reservoir performance is controlled by subseismic faults and oyster bioherms acting as thief zones. Numerical simulations of secondary recovery processes reveal strong channelling of fluid flow into high-permeability layers as the primary control for oil recovery. However, appropriate reservoir-engineering solutions, such as optimizing well placement and injection fluid, can reduce channelling and increase oil recovery.

Simulating flow through forward sediment model stratigraphies: insights into climatic control of reservoir quality in isolated carbonate platforms

Whilst sophisticated multiphase fluid flow models are routinely employed to understand behaviour of oil and gas reservoirs, high-resolution data describing the three-dimensional (3D) distribution of rock characteristics is rarely available to populate models. We present a new approach to developing a quantitative understanding of the effect of individual controls on the distribution of petrophysical properties and their impact on fluid flow. This involves simulating flow through high-detail permeability architectures generated by forward modelling of the coupled depositional–diagenetic evolution of isolated platforms using CARB3D + . This workflow is exemplified by an investigation of interactions between subsidence and climate, and their expression in spatial variations in reservoir quality in an isolated carbonate platform of similar size and subsidence history to the Triassic Latemar Platform. Dissolutional lowering during subaerial exposure controls platform-top graininess via platform top hydrodynamics during the subsequent transgression. Dissolved carbonate is reprecipitated as cements by percolating meteoric waters. However, associated subsurface meteoric dissolution generates significant secondary porosity under a more humid climate. Slower subsidence enhances diagenetic overprinting during repeated exposure events. Single-phase streamline simulations show how early diagenesis develops more permeable fairways within the finer-grained condensed units that can act as thief zones for flow from the grainier but less diagenetically altered cyclic units.

Numerical modeling of cemented wellbore leakage from storage reservoirs with secondary capture due to thief zones

Abstract A 3D, multi-phase, multi-component numerical model of injection into a storage reservoir with an abandoned wellbore is developed. A shallow aquifer is modeled above the storage reservoir separated by a caprock layer. An intermediate permeable layer assumed to be a thief zone is modeled. The abandoned wellbore penetrates the entire model from the surface, through shallow aquifer and thief zone to the bottom of the primary storage reservoir. The amount of CO 2 captured within the thief zone and released to the shallow aquifer and atmosphere is assessed. A Latin Hypercube sample evaluates the effects of variations in CO 2 injection rate, depth of the reservoir, relative depth of the thief zone, and permeability of the wellbore, thief zone, and shallow aquifer. In addition, full factorial design parameter studies evaluate the effect of differing wellbore permeabilities above and below the thief zone. Analyses of the Latin Hypercube sample and parameter studies provide indications of the necessary conditions for secondary capture in thief zones and potential for leakage to the shallow aquifer and atmosphere.

Produced-Water-Chemistry History Matching Using a 1D Reactive Injector/Producer Reservoir Model

SummaryUnderstanding connectivity between injection and production wells is valuable information for reservoir management. Typically, connectivity might be evaluated by use of downhole-pressure information or by injecting tracers into the reservoir. A less-established but inexpensive technique is to history match produced-water compositions. For example, previous studies with this method have identified barriers to flow in reservoirs. Information on connectivity is also beneficial to scale management, particularly that in which sulfate (SO4) -rich seawater is injected into reservoirs containing formation water rich in divalent cations [i.e., barium (Ba), strontium (Sr), calcium (Ca)], because, in these cases, the sulfate mineral-scaling conditions in production wells are a function of the physical properties of the flow paths connecting the injection and production wells (Wright et al. 2008).In this study, we have considered this latter relationship from a reverse perspective and explored the potential of history matching produced-water compositions to understand the physical properties of flow paths connecting injection and production wells for reservoirs under seawater flood. We have performed this history matching with a 1D reactive transport model connecting an injector and a producer through a number of noncommunicating layers characterized by permeability, porosity, and height (completion interval) (Vazquez et al. 2009). The model simulates the injection of seawater, the mixing of the seawater with reservoir-formation brine, and the subsequent deposition of sulfate scales (barium and calcium sulfate among others) in the reservoir under equilibrium and kinetic conditions. The results of interest are the predicted produced-water compositions over time from the model, similar to the approach presented by McCartney et al. (2012); Tjomsland et al. (2010); and Wright et al. (2008).The model has been used to demonstrate the way in which produced-water compositions vary as the physical properties of the layers between the wells are modified, and, particularly, the way in which they vary in the presence of thief zones. Finally, a stochastic method was applied—in particular a particle-swarm-optimization (PSO) algorithm—for the automatic history matching of actual produced-water compositions from individual wells in fields under seawater flooding. The results are promising and show that this technique can provide valuable information about the nature of interwell connectivity.

Characterization of high-permeability streak in mature waterflooding reservoirs using pressure transient analysis

Abstract The characterization of thief zone, which evolves from long-term waterflooding, has become imperative in the enhanced oil recovery process. As one typical kind of thief zone, pressure transient performance of high-permeability streak is analyzed in this work. A mathematical model is established for a well intersected by a high-permeability streak, and the solution in Laplace space is derived by Ozkan's source function. To ensure improved accuracy and better efficiency, the solution is inverted into real space numerically through de Hoog Algorithm. Investigation of the pressure transient behavior indicates that the process can be divided into three periods: (1) the early-time flow period, which is comprised of streak storage-type flow and bilinear flow; however, it occurs too early to be of practical interest; (2) the linear flow from the formation to the streak, which is characterized by a half-slope straight line; (3) pseudo-radial flow, exhibited by a horizontal line on the derivative curve. The sensitivities of corresponding parameters have also been discussed. Furthermore, Gravitational Search Algorithm (GSA) is successfully applied as a non-linear regression technology to match measured pressure with this model and to characterize high-permeability streak. Compared to previous technologies, this approach is more cost-effective and less time-consuming. Moreover, the quantitative characterization of high-permeability streak can play a very important role in the design of conformance control project. Thus this approach has been extensively employed in many China Oilfields. And field cases are also presented to substantiate its validity.

Microcapsule flow behaviour in porous media

This article investigates the possibility of using micro-capsules, with a gelling agent, hydroxypropyl cellulose, in the core, during enhanced oil recovery. The aim is to block off high permeability regions of a formation known as thief zones, thereby diverting the chase injection water into adjacent unswept low permeability regions. Temperature triggered micro-capsules were made by polymer precipitation through a solvent evaporation method, with poly(lactic-co-glycolic) acid as the polymer shell. Release studies with methylene blue demonstrated the temperature induced release from these micro-capsules. A customised tank was made to allow porous media flow and single permeability experiments were conducted. Even without the gelling agent, the micro-capsules gradually blocked the ballotini pore network. However, by varying the tank temperature, a drop in permeability was observed when the capsules released their core. Experiments with two permeability regions showed that the micro-capsules clogged up the high permeability layer more than the low permeability region.

Numerical Simulation of SAGD Recovery Process in Presence of Shale Barriers, Thief Zones, and Fracture System

This study presents a numerical investigation for evaluating the potential applicability of the steam-assisted gravity drainage (SAGD) recovery process under complex reservoir conditions such as shale barriers, thief zones with bottom and/or top water layers, overlying gas cap, and fracture systems in the McMurray and Clearwater formation. The simulation results indicated that the near-well regions were very sensitive to shale layers, and only long, continuous shale barriers (larger than 50 m or 25%) affect the SAGD performance in these well regions. In addition, the thief zones had a strongly detrimental effect on SAGD. The results also showed that the SAGD recovery process was enhanced in the presence of vertical fractures but horizontal fractures were harmful to recovery. Fracture spacing is not an important parameter in the performance of a steam process in fractured reservoirs and extending horizontal fractures will reduce ultimate oil recovery in the SAGD process. This article provides a guideline for SAGD operations in complex geological reservoirs.

Polymer Systems for Water Shutoff and Profile Modification: A Review Over the Last Decade

SummaryUnwanted water production is a serious issue in oil- and gas-producing wells. It causes corrosion, scale, and loss of productivity. One method of treating this problem is to chemically reduce unwanted water. This paper discusses the use of polymer systems for this purpose and presents a thorough review of available literature over the last decade. In this paper, field-application data for various polymer systems are summarized over the range of 40 to 150°C (104 to 302°F). These applications cover a wide range of permeabilities from 20 to 2,720 md in sandstone and carbonate reservoirs around the globe. Moreover, the review revealed that the last decade of developments can be categorized into two major types. The first type is polymer gels for total water shutoff in the near-wellbore region, in which a polymer is crosslinked with either an organic or an inorganic crosslinker. The second type is concerned with deep treatment of water-injection wells diverting fluids away from high-permeability zones (thief zones). These thief zones take most of the injected water, which results in a large amount of unrecovered oil. For the total-blocking gels, various systems were identified, such as polyurethane resins, chromium (Cr3+) crosslinking terpolymers, Cr3+ crosslinking foamed partially hydrolyzed polyacrylamide (PHPA), and nanoparticle polyelectrolyte complexes (PECs) sequestering Cr3+ for elongation of its gelation time with PHPA. In addition, polyethylenimine (PEI) was identified to crosslink various polyacrylamide- (PAM-) based polymers. The Petróleos de Venezuela S.A. (PDVSA) Research and Development Center developed a PAM-based thermally stable polymer and an organic crosslinker. The system is applicable for a wide temperature range from 50 to 160°C (130 to 320°F).For the deep modification of water-injection profiles in water-injection wells, two systems were identified: microspheres prepared from PAM monomers crosslinked with N,N′-methylenebisacrylamide and microspheres produced by crosslinking 2-acrylamido-2-methylpropane sulfonic acid (AMPS) with diacrylamides and methacrylamides of diamines (thermally activated microparticles known as Bright Water). This paper highlights all major developments in these areas.

Recovery efficiency from a turbidite sheet system: numerical simulation of waterflooding using outcrop-based geological models

A series of waterflood simulations were performed to investigate the effect of basinal position and facies permeability within a turbidite sheet system on oil recovery efficiency. Simulations used three-dimensional outcrop models of the Peïra Cava system, comprising gravel, sandstone, thin-bedded heterolithic and mudstone facies. Recovery efficiency declines with increasing permeability heterogeneity and is influenced by the interaction of vertical bed-permeability trends and flood-front gravity slumping. The occurrence of gravels with permeabilities lower than overlying sandstones produces optimum recoveries. High permeability gravels act as thief zones, enhanced by downward gravity slumping, reducing normalized recovery by up to 34 %. The effect of thief zones on recovery is related to their permeability contrast, abundance, thickness, lateral continuity, vertical position within permeable units and the permeability of underlying facies. Proximal to distal stratigraphic variations produce relatively small differences in normalized recovery of up to 13 % in models with the highest permeability heterogeneity. Differences in recovery are interpreted to reflect spatial trends in facies architecture, which determine the effectiveness of high permeability gravel thief zones. The poorest recovery is recorded from the medial model where recovery is lower than distal areas because of higher gravel abundance and thicknesses and lower compared to proximal areas because of the higher lateral continuity of gravels and underlying low-permeability mudstones.

Improvement of SAGD by N2 Injection in Oil Sand Reservoir with Thief Zone

Improvement of SAGD by N2 Injection in Oil Sand Reservoir with Thief Zone