Trapped Oil Research Articles

Dynamic Model of Gears with Trapped Oil and Coupled Analysis in External Spur-Gear Pump

In order to understand the vibration characteristics of gears based on trapped-oil in external spur-gear pump, from the calculations of trapped-oil pressure and hydraulic load and contact stiffness and trapped-oil stiffness, etc., a dynamic model coupled with trapped-oil pressure was derived for the gears, then an iterative operation based on Runge-Kutta method was used for analyzing the model, therefore the data related to trapped-oil pressure and the vibration displacement and the vibration velocity were obtained in a periodic of trapped oil, and the impact of different backlash value and different distance between two unloading grooves on trapped oil pressure and dynamic characteristics of gears was briefly analyzed. All results of simulation showed that trapped-oil pressure and trapped-oil stiffness had greater impact on vibration characteristics of gears in external spur-gear pump, trapped-oil stiffness could reduce the vibration of the gears; in simulation of trapped-oil pressure, dynamic trapped-oil model related to dynamic characteristics of gears more accurate than the static trapped-oil model irrelated to dynamic characteristics of gears; the trapped-oil pressures in two trapped-oil cavity were different, the vibration characteristics of gears was better that in larger backlash value, etc.. Finally, by the trapped-oil stiffness of the external gear pump is unique, the important conclusions are educed that the vibration of gears in external spur-gear pump is indeed different from conventional gears and so on.

Network Modeling of EOR Processes: A Combined Invasion Percolation and Dynamic Model for Mobilization of Trapped Oil

A novel concept for modeling pore-scale phenomena included in several enhanced oil recovery (EOR) methods is presented. The approach combines a quasi-static invasion percolation model with a single-phase dynamic transport model in order to integrate mechanistic chemical oil mobilization methods. A framework is proposed that incorporates mobilization of capillary trapped oil. We show how double displacement of reservoir fluids can contribute to mobilize oil that are capillary trapped after waterflooding. In particular, we elaborate how the physics of colloidal dispersion gels (CDG) or linked polymer solutions (LPS) is implemented. The linked polymer solutions consist of low concentration partially hydrolyzed polyacrylamide polymer crosslinked with aluminum citrate. Laboratory core floods have shown demonstrated increased oil recovery by injection of linked polymer solution systems. LPS consist of roughly spherical particles with sizes in the nanometer range (50–150 nm). The LPS process involve mechanisms such as change in rheological properties effect, adsorption and entrapment processes that can lead to a microscopic diversion and mobilization of waterflood trapped oil. The purpose is to model the physical processes occurring on pore scale during injection of linked polymer solutions. A sensitivity study has also been performed on trapped oil saturation with respect to wettability status to analyze the efficiency of LPS on different wettability conditions. The network modeling results suggest that weakly wet reservoirs are more suitable candidates for performing linked polymer solution injection.

Influence of relative permeabilities on chemical enhanced oil recovery

The main objective of chemical flooding is to mobilize the trapped oil remaining after a secondary recovery by waterflooding. This purpose is achieved by lowering the oil-water interfacial tension and producing partial miscibility between both phases. The chemical partition among phases (phase behavior) influences all other physical properties. In particular, it affects residual saturations determining relative permeability curves. Relative permeabilities rule the flow of each phase through the porous medium, so they play an essential role in oil recovery. Therefore, in this work we study the influence of relative permeabilities on the behavior of a surfactant-polymer flooding for the three different types of phase behavior. This analysis is performed applying the 3D compositional numerical simulator UTCHEM developed at the University of Texas at Austin. From the examples studied, we conclude that the influence of relative permeabilities depends on the type of phase behavior, i.e., as microemulsion relative permeability decreases, oil recovery increases for Types II(+) and III while slightly decreases for Type II(-). Moreover, a better displacement efficiency is observed for Types II(+) and III, because they behave similarly to a miscible displacement.

A New DSC-Based Method to Determine the Wax Porosity of Mixtures Precipitated from Crude Oils

Wax precipitation is one of the most important problems in flow assurance. The correct prediction of the wax appearance temperature (WAT) and the wax precipitation curve (WPC) is essential to anticipate potential solutions for this problem. The determination of both WAT and WPC requires reliable data on the amount of precipitated wax and the trapped crude oil remaining in these mixtures. The estimation of the latter is difficult due to the scarcity of experimental methodologies. In this work, a method based on differential scanning calorimetry (DSC) was developed to determine the trapped crude oil of precipitated mixtures. The WPCs were experimentally determined by fractional precipitation and DSC analysis for a variety of crude oils. The comparison of these curves requires the correction of the former by subtracting the trapped crude oil remaining in the precipitated mixtures. The trapped crude oil was calculated using two methods: one based on proton nuclear magnetic resonance (1H NMR) previously developed and the other based on DSC, developed in this work. This method considers that the gel formed when decreasing the temperature contains not only solids, but also occluded crude oil. The values of trapped crude oil estimated by both methods were used to correct experimental WPC. The comparison between corrected WPC and those obtained by DSC analysis showed the superiority of DSC over 1H NMR to calculate the amount of trapped crude oil.

Hydrocarbon generation evaluation of Permo-Carboniferous source rocks in Qinggu-2 well in Dongpu depression, China

The Dongpu (东濮) depression is a Mesozoic subsidence and Cenozoic fault basin developed within the North China craton. Since the deposition of Permo-Carboniferous hydrocarbon source rock, the depression has undergone many tectonic disturbances and uplifts. The source rocks have undergone nonuniform uplift, deformation, deep burying, and magmatism, and those led to an interrupted or stepwise evolution of the hydrocarbon source rocks in Qinggu (庆古)-2 well. We have investigated the history of burying, heating, and hydrocarbon generation of the Permo-Carboniferous hydrocarbon source rocks not just on the basis of tectonic disturbance and deep burying, but also with new studies in apatite fission track analysis, fluid inclusion measurements, and the application of the numerical simulation of EASY%R o. The heating temperature of the source rocks pulsated upward from Indosinian to Himalayan stages and reached a maximum during early Himalayan. This led to the stepwise increases of organic maturation and multiple stages of hydrocarbon generation. This study delineated the tectonic stages, maturity evolved ranges, and the intensity of hydrocarbon generation of Permo-Carboniferous source rocks in Qinggu-2 well. The hydrocarbon generation mainly occurred during Indosinian and early Himalayan. The early Himalayan stage hydrocarbon generation is the larger one, but the Dongying (东营) movement, which happened at the end of early Himalayan, may destroy the trapped oil and gas. Thereby, future exploration will need to pay more attention to the Dongying movement effect in Qinggu-2 well area, and it may get new breakthrough in Permo-Carboniferous oil and gas.

Characterization of Oil Precipitate and Oil Extracted from Condensed Corn Distillers Solubles

AbstractOil extracted from condensed corn distillers solubles (CCDS) can form a semi‐solid and waxy precipitate at the bottom of containers during storage. CCDS is a good source to recover oil, and such oil can be converted to biodiesel. Precipitate formation in the extracted oil is mainly a physical stability problem, but it may become a performance problem for biodiesel. The objective of the present work was to determine the composition of the CCDS oil precipitate and also determine if valuable phytosterols were present in high concentration. The free fatty acid (FFA) content was very high, 35.7%, and fatty acid composition of the FFA fraction was predominantly palmitic acid, 70.3%. The solid appearance was mainly due to a high percentage of high‐melting point free saturated fatty acid. The total unsaponifiable matter was 2.0%, and total phytosterol content was 8.6 mg/g of CCDS oil precipitate. Therefore, CCDS oil precipitate is a not an enriched source of phytosterols compared to total sterols present in crude corn oil (15.6 mg/g oil). The wax content was high, 2.5 mg/g of CCDS oil precipitate compared to 0.5 mg/g of crude corn oil. CCDS oil that is uncentrifugable but polar solvent extractable (trapped oil fraction) was also characterized and found to contain more polar lipids than those in the free oil fraction (centrifugable oil).

The effects of wettability and trapping on relationships between interfacial area, capillary pressure and saturation in porous media: A pore-scale network modeling approach

We use a three-dimensional mixed-wet random pore-scale network model to investigate the impact of wettability and trapping on the relationship between interfacial area, capillary pressure and saturation in two-phase drainage and imbibition processes. The model is a three-dimensional network of interconnected pores and throats of various geometrical shapes. It allows multiple phases to be present in each capillary element in wetting and spreading layers, as well as occupying the center of the pore space. Two different random networks that represent the pore space in Berea and a Saudi Arabia reservoir sandstone are used in this study. We allow the wettability of the rock surfaces contacted by oil to alter after primary drainage. The model takes into account both contact angle and trapping hystereses. We model primary oil drainage and water flooding for mixed-wet conditions, and secondary oil injection for a water-wet system. The total interfacial area for pores and throats are calculated when the system is at capillary equilibrium. They include contributions from the arc menisci (AMs) between the bulk and corner fluids, and from the main terminal menisci (MTMs) between different bulk fluids. We investigate hysteresis in these relationships by performing water injection into systems of varying wettability and initial water saturation. We show that trapping and contact angle hystereses significantly affect the interfacial area. In a strongly water-wet system, a sharp increase is observed at the beginning of water flood, which shifts the area to a higher level than primary drainage. As we change the wettability of the system from strongly water-wet to strongly oil-wet, the trapped oil saturation decreases significantly. Starting water flood from intermediate water saturations, greater than the irreducible water saturation, can also affect the non-wetting phase entrapment, resulting in different interfacial area behaviors. This can increase the interfacial area significantly in oil-wet systems. A qualitative comparison of our results with the experimental data available in literature for glass beads shows, with some expected differences, an encouraging agreement. Also, our results agree well with those generated by the previously developed models.

Displacement of oil by different interfacial tension fluids under ultrasonic waves

Insight into the physical principles governing the mobilization of oil by ultrasonic waves is vital for developing novel techniques of oil extraction. Various mechanisms such as peristaltic transport due to mechanical deformation of the pore walls, reduction of capillary forces due to the destruction of surface films, coalescence of oil drops due to the Bjerknes forces, oscillation and excitation of capillary trapped oil drops, forces generated by cavitating bubbles, and sonocapillary effects may be responsible for enhancing the flow of oil through porous media in the presence of an acoustic field. This paper aims at analyzing the influence of high-frequency, high-intensity ultrasonic radiation on the immiscible and miscible displacement. To analyze the viscous displacement under ultrasonic waves, experiments were performed on Hele–Shaw models. Immiscible (for mineral oil–brine and mineral oil–surfactant pairs) and miscible (for mineral oil–pentane, mineral oil–kerosene and mineral oil–2-propanol pairs) displacement experiments were performed. Changes on the displacement fronts and patterns were observed under ultrasound. Fractal techniques were used to analyze the changes and correlate them to the intensity of ultrasonic waves.

Analysis of capillary interaction and oil recovery under ultrasonic waves

Although, the effects of ultrasonic irradiation on multiphase flow through porous media have been studied in the past few decades, the physics of the acoustic interaction between fluid and rock is not yet well understood. Various mechanisms may be responsible for enhancing the flow of oil through porous media in the presence of an acoustic field. Capillary related mechanisms are peristaltic transport due to mechanical deformation of the pore walls, reduction of capillary forces due to the destruction of surface films generated across pore boundaries, coalescence of oil drops due to Bjerknes forces, oscillation and excitation of capillary trapped oil drops, forces generated by cavitating bubbles, and sonocapillary effects. Insight into the physical principles governing the mobilization of oil by ultrasonic waves is vital for developing and implementing novel techniques of oil extraction. This paper aims at identifying and analyzing the influence of high-frequency, high-intensity ultrasonic radiation on capillary imbibition. Laboratory experiments were performed using cylindrical Berea sandstone and Indiana limestone samples with all sides (quasi-co-current imbibition), and only one side (counter-current imbibition) contacting with the aqueous phase. The oil saturated cores were placed in an ultrasonic bath, and brought into contact with the aqueous phase. The recovery rate due to capillary imbibition was monitored against time. Air–water, mineral oil–brine, mineral oil–surfactant solution and mineral oil-polymer solution experiments were run each exploring a separate physical process governing acoustic stimulation. Water–air imbibition tests isolate the effect of ultrasound on wettability, capillarity and density, while oil–brine imbibition experiments help outline the ultrasonic effect on viscosity and interfacial interaction between oil, rock and aqueous phase. We find that ultrasonic irradiation enhances capillary imbibition recovery of oil for various fluid pairs, and that such process is dependent on the interfacial tension and density of the fluids. Although more evidence is needed, some runs hint that wettability was not altered substantially under ultrasound. Preliminary analysis of the imbibition recoveries also suggests that ultrasound enhances surfactant solubility and reduce surfactant adsorption onto the rock matrix. Additionally, counter-current experiments involving kerosene and brine in epoxy coated Berea sandstone showed a dramatic decline in recovery. Therefore, the effectiveness of any ultrasonic application may strongly depend on the nature of interaction type, i.e., co- or counter-current flow. A modified form of an exponential model was employed to fit the recovery curves in an attempt to quantify the factors causing the incremental recovery by ultrasonic waves for different fluid pairs and rock types.

Influence of Wettability on Foamed Gel Mobility Control Performance in Unconsolidated Porous Media

Abstract Practically all enhanced oil recovery (EOR) processes require mobility control techniques to minimize channeling, gravity override, and viscous fingering of the displacing phase. In oil reservoirs that contain free gas, high gas-oil ratio production is a widespread problem, because gas segregates as a result of its higher mobility. This condition may cause reduced oil production rates, loss of drive energy, loss of recoverable oil, and problems with fluid processing. Use of foam as mobility-control fluid has shown promise in a wide range of EOR techniques including steam flooding, CO2, light hydrocarbon or N2 injection, and chemical flooding. The success of any mobility control process, including foams, is determined by the microscopic displacement efficiency of the displacing fluid at pore level. Microscopic displacement efficiency is determined by the interactions of rock pore geometry and interface boundary conditions, which constitute the reservoir wettability. To date, limited information has been published regarding the role of wettability in the performance of foams as a mobility control agent, and accordingly, more evaluation is needed. The focus of this experimental research was to determine the effect of wettability on the performance of foamed gels in displacing oil and in its efficiency as a mobility control and blocking agent. The experimental observations were made through a series of displacement tests using unconsolidated porous media with an average permeability of 209 D. The wettability of the porous media was modified using an organic coating solution. The oil phase used was Soltro1 ®10 and the foamed gel formulation was based on a partly hydrolyzed polyacrylamide crosslinked with chromium (III) acetate, and an anionic surfactant. The experimental outcome indicated that mobility control performance of foamed gels is sensitive to the wettability of the porous media. Under oil-wet conditions, foamed gel demonstrated superior efficiency as a mobility control and/or blocking agent. Furthermore, the injection of foamed gels in high permeability porous media demonstrated an efficient fluid diverting capability, which renders important additional oil recovery. Introduction Many enhanced oil recovery processes use gas drive to displace trapped oil, such as steam flood and CO2, floods. The sweep efficiency of these methods is often low because of the unfavourable mobility ratio of gas to oil. Therefore, gas tends to override or finger through oil(1, 2). Improving gas mobility to increase reservoir sweep can add significantly to recoverable reserves and impact the economics of these tertiary recovery processes(3). The use of surfactant-stabilized foams to counteract such problems was suggested decades ago(4). The use of foam is advantageous compared with the use of a single fluid of the same nominal mobility because the foam, which usually has an apparent viscosity greater than the displaced fluids, lowers the gas mobility in the swept or higher permeability parts of the formation. This diverts at least some of the displacing gas into other parts of the formation that were previously unswept or underswept. From these underswept areas, additional oil is recovered.

Vibration-induced mobilization of trapped oil ganglia in porous media: Experimental validation of a capillary-physics mechanism

The development of methods for mobilizing residual organic liquids trapped in porous media is becoming increasingly important as world demand for oil increases and because of the need to remediate aquifers degraded by slow-dissolving organic contaminants. Low-frequency elastic wave stimulation is one such technique, but until recently the lack of a mechanistic understanding of the effects of vibration on mobilization of oil ganglia has prevented the method from being applied predictably in the field. Recently, a simple capillary-physics mechanism has been developed to explain vibration-induced mobilization of a trapped non-wetting organic phase in porous media. Specific predictions that follow from this hypothesized mechanism are that vibrations will be most effective in mobilizing trapped oil when the acceleration amplitude is within an optimal range of values (that depend on the magnitudes of the capillary forces trapping the ganglia and the imposed static pressure gradients) and for sufficiently low vibration frequencies. In this paper we describe two-dimensional glass micromodel experiments that support these predictions.

Use of X-ray computed microtomography to understand why gels reduce relative permeability to water more than that to oil

X-ray computed microtomography (XMT) was used to investigate why gels reduce relative permeability to water more than that to oil in strongly water-wet Berea sandstone. XMT allows saturation differences to be monitored for individual pores during various stages of oil, water, and gelant flooding. The method also characterizes distributions of pore size, aspect ratio, and coordination number for the porous media. We studied a Cr(III) acetate–HPAM gel that reduced permeability to water (at S or) by a factor 80–90 times more than that to oil (at S wr). In Berea, the gel caused disproportionate permeability reduction by trapping substantial volumes of oil that remained immobile during water flooding (i.e., 43.5% S or before gel placement versus 78.7% S or after gel placement). With this high trapped oil saturation, water was forced to flow through narrow films, through the smallest pores, and through the gel itself. In contrast, during oil flooding, oil pathways remained relatively free from constriction by the gel.

Oil Spill in the Iguassu River – Araucaria, Parana, Brazil Cleaning and Restoration of Rivers and Inundation Areas

ABSTRACT On July 16, 2000 a major oil spill occurred at the side of the Araucaria refinery of Petrobras. A total of 4,000 m3 of a light crude oil (41° API) ran down along a small two kilometers creek referred to as Arroio Saldanha, crossing and contaminating a series of four wetlands. The oil discharged into the Barigüi River, a tributary of the Iguassu River. It's estimated that twenty per cent of all the oil spilled volatilized. After running along the creek and its wetlands, the oil contaminated 6 kilometers of the Barigüi River and 60 kilometers of the Iguassu River. A comprehensive oil recovery emergency response operation was immediately engaged to clean the impacted area and the rivers. Some 3000 persons worked around the clock during the peak of the operations. Helicopters, trucks, oil recovering boats, light boats, mechanical excavators, dredgers and 3,200 meters of retention booms were used. Roads and accesses were reformed or built. The overall emergency response effort proved to be successful; in nine days, all of the free oil was removed from the rivers. The cleaning of the riverbanks and inundation areas was completed in three months. The Saldanha Creek and the four wetlands areas upgradient of the Barigüi River retained approximately 70 per cent of all of the oil spilled, all superficial oil was removed until it could not move superficially, the remaining oil impregnated in the upper soil profiles. Since then, various remediation techniques were implemented to remediate both, soil surface water and groundwater. The upper portion of the soil profile is remediated with bioremediation, using natural indigenous microorganism. This technique consists in cultivating the soil with mechanical agricultural equipment or manually where accessibility does not allow the use of mechanical equipment. Nutrients and other amendments can be added when required. In some cases soil are bioaugmented with microorganisms of the “landfarming” cells of the refinery. This technique is a variant of the landfarming technique that has been studied at the Repar (Refinaria Presidente Getúlio Vargas) refinery for more than ten years. Such technique has proven to be more efficient than traditional landfarming. The soil below 40 centimeters cannot be remediated with this technique. Soils at such depth are being recovered through a series of drainage and injection trenches. Water injected in the injection trench forces the free and trapped oil to move laterally to the recovery trenches. The largest contaminated swamp was transformed in a treatment wetland and its recovery is being monitored and adjusted to quicken the recovering, thus minimizing interference with the natural ecosystem.

Capillarity‐induced resonance of oil blobs in capillary tubes and porous media

We investigate the excitation by sound waves of capillary trapped oil blobs. The three‐phase contact lines either remain pinned to the heterogeneities of the solid surface or slide if sound waves are applied. We derive approximate, analytical expressions for the resonance of oil blobs in capillary tubes for both types of contact line behavior. Based upon these simple model systems, we conclude that resonance of oil blobs is significant for coarse‐grained but not fine‐grained media.

Wettability heterogeneities in gas injection; experiments and modelling

We carried out experiments to study the effect of wettability heterogeneities on: (1) displacement mechanisms, (2) sweep efficiency and (3) trapped oil quantities and fluid distribution in three-phase gas injection and developed a theoretical simulator. Secondary gas injection experiments was conducted in transparent glass micromodels of heterogeneous wettability. Oil-wet patches in a water-wet matrix were obtained by selective silane grafting on the glass surface. Different heterogeneity patterns were considered for the same oil-wet over water-wet surface ratio. Displacement sequences were video-recorded and fluid saturations determined by image analysis. A theoretical model of three-phase flow in a porous structure was developed. In this model the porous medium is simulated as a network of interconnected pores. The model permits an imposition of heterogeneous wettability by assigning different water-oil contact angles according to the desired wettability pattern. The calculation of flow within the network takes into account the flow of oil through wetting and spreading films and the displacement mechanisms observed in the transparent micromodels. Comparison between experimental results and simulations shows that the size and distribution of wettability heterogeneities strongly affects microscopic and macroscopic behaviour during gas injection.

The Effect of Horizontal Well Orientation On Secondary Biopolymer Flooding of Safaniya Crude Oil

Abstract This paper presents an experimental investigation of the effect of horizontal well orientation on xanthan biopolymer flooding of Safaniya crude oil, in Saudi Arabia, through a horizontal well in laboratory scaled models. Two models were scaled according to two possible horizontal-vertical field arrays to study the effect of horizontal well orientation on oil recovery. A third model was designed for vertical wells only to compare between horizontal and vertical injectors. Different biopolymer concentrations were used to determine the most effective concentration for secondary biopolymer flooding of Safaniya crude oil. Oil recovery and oil cut due to biopolymer injection through a horizontal injector and a vertical injector were undertaken for comparison. The results showed that displacing Safaniya crude oil with 0.15% biopolymer concentration in the secondary phase yielded the highest oil recovery. A diagonally-oriented horizontal well in the mixed arrays accelerated and increased the oil recovery more than a parallel-oriented horizontal well and a vertical well. A parallel-oriented horizontal well resulted in a larger unswept area which yielded trapped oil in the model and consequently resulted in a lower oil recovery than even a vertical injector. Introduction Horizontal-well technology was considered to be the most significant technology in the oil and gas industry of the 1980's(1). Early applications were devoted to exploiting thin reservoirs, reservoirs suffering a high tendency to water cone, and reservoirs of high vertical permeability. Recently, horizontal-well technology was applied in thermal recovery methods, gas injection, waterflooding, chemical flooding, gas storage, and exploiting conventional reservoirs(2–7). Chemical flooding methods for enhanced oil recovery have a long history, but in the last decade they have received an extraordinary amount of attention from researchers and operators alike. Polymer flooding is one of the methods which has been tested and developed for conventional as well as heavy oil recovery(8–11). Polymer flooding involves the addition of high molecular weight polymers to the injection water to improve the mobility ratio by increasing the viscosity of the water and by reducing the effective permeability of water. This paper addresses the use of biopolymer solutions for the recovery of Safaniya crude oil, which is considered to be heavy crude oil, in the secondary phase of oil recovery through a horizontal well. It also studies the effect of horizontal well orientation on the oil recovery and oil cut. Literature Review The application of polymer flooding has been well established, not only in laboratory studies but also in field application, for some time. The history of polymer flooding goes back to the year 1964 when Pye(10) and Sandiford(11) demonstrated that the injection water mobility can be reduced significantly by the addition of a small amount of a water soluble polymer. In 1966, Mungan et al.(12) studied the rheological properties of the flow characteristics of polymer solutions and classified them as pseudoplastic fluids. Later research by Mungan(13) found that the apparent viscosity of partially hydrolyzed polymer solutions was affected by temperature; thermal degradation occurred between 135 °C and 300 °C.

Capillary Entrapment Caused by Small-Scale Wettability Heterogeneities

SummarySmall-scale heterogeneities are abundant in oil reservoirs. It is well known that these heterogeneities can reduce the displacement efficiency of immiscible flooding because of capillary entrapment of oil. A typical heterogeneous facies is the laminated crossbed set with alternating high- and low-permeability laminae. Apart from this heterogeneity in grain size, the wettability of the laminae can also differ. The laminae can contain different minerals with different wetting characteristics, and wettability can be affected by adsorption of hydrocarbons to the grain surface. In this paper we focus on the effects of wettability on the entrapment. We describe a procedure that allows the reader to quantify the trapped oil saturation depending on absolute permeability, relative permeability, and capillary pressure curves of the foreset laminae, on the basis of a simplified crossbed geometry. The example calculations show the sensitivity of various parameters with respect to the magnitude of trapping.

Effect of subsurface heterogeneity on free-product recovery from unconfined aquifers

Free-product record system designs for light-hydrocarbon-contaminated sites were investigated to evaluate the effects of subsurface heterogeneity using a vertically integrated three-phase flow model. The input stochastic variable of the areal flow analysis was the log-intrinsic permeability and it was generated using the Turning Band method. The results of a series of hypothetical field-scale simulations showed that subsurface heterogeneity has a substantial effect on free-product recovery predictions. As the heterogeneity increased, the recoverable oil volume decreased and the residual trapped oil volume increased. As the subsurface anisotropy increased, these effects together with free- and total-oil contaminated areas were further enhanced. The use of multiple-stage water pumping was found to be insignificant compared to steady uniform pumping due to reduced recovery efficiency and increased residual oil volume. This observation was opposite to that produced under homogeneous scenarios. The effect of subsurface heterogeneity was enhanced at relatively low water pumping rates. The difference in results produced by homogeneous and heterogeneous simulations was substantial, indicating greater attention should be paid in modeling free-product recovery systems with appropriate subsurface heterogeneity.

The Qishn Formation, Yemen: lithofacies and hydrocarbon habitat

The Barremian-Aptian Qishn Formation of Yemen is broadly described in the context of its role as the lowest widespread transgressive unit of the Cretaceous system in the country and of the two laterally equivalent lithofacies groups that reflect the advance of the Cretaceous sea from east to west. This is undertaken against the background of the tectonic events that preceded its deposition and those that followed it during the remainder of the Cretaceous, so as to better understand its hydrocarbon habitat. The Qishn Formation clastics (sands) have proved to be an excellent and major oil reservoir in eight recent oil discoveries made in the area between the Mukalla and Hoowarin highs of the Hadhramaut province of Yemen. The oil in these discoveries, like the oil (and gas) in 14 of the currently remaining 15 fields and discoveries in the country, is generated from Upper Jurassic organic-rich source rocks and vertically charged the Qishn reservoir in the absence of an effective intervening seal. Subsurface data from the recent discoveries area and from sparse subsurface control in the Jeza' basin to its east indicate the presence in this region of an areally more limited pre-Qishn Cretaceous platform sequence and suggests that the Jeza' basin was an early Cretaceous marine embayment between still positive land masses on either side in which thicker Cretaceous sequences continued to be laid down after the bordering areas were inundated by the Qishn transgression. These basinal sequences probably include Qishn source shale levels similar to those found in the southern offshore area; there they are mainly immature, however, or else do not appear to have generated identifiable trapped oil. The Jeza' basin thus appears to hold promising untested potential for oil sourced by unpenetrated Qishn levels (in addition to good Upper Cretaceous Mukalla Formation source levels and Upper Jurassic levels, where preserved and not too deeply buried) which would be at varying degrees of oil and gas maturity. These sources could charge, by multi-stage migration from the ‘kitchen’ areas, various Cretaceous reservoirs, including Qishn clastics or carbonates, in any updip traps.

Displacement of trapped oil from water-wet reservoir rock

Displacement of oil trapped in water-wet reservoirs was analyzed using percolation theory. The critical capillary number of the CDC (Capillary Desaturation Curve) was be predicted based on the pore structure of the medium. The mobilization and stability theories proposed by Stegemeier were used to correlate oil cluster length to the capillary number needed to mobilize the trapped oil. Under the assumption that all pore chambers have the same size, a procedure was developed using the drainage capillary pressure curve and effective accessibility function to predict the CDC curve for a given medium. The prediction of critical capillary numbers was compared with the experimental data from 32 sandstone samples by Chatzis and Morrow. Also, the CDC curve of one sandstone sample was calculated using the procedure developed in this work and compared with the measured data. Very good agreements were obtained.