5-spot Pattern Research Articles

Experimental investigation and numerical simulation of relative permeability modifiers during water shut-off

Relative permeability modifier (RPMs) is a water-shutoff technique that is implemented mostly in high water-producing wells when conventional mechanical isolation methods are not suitable. To optimize RPM injection treatment, numerical simulation is the most effective tool. In this study, laboratory experiments were conducted to investigate the rheology and characteristics properties of newly formulated polymer grafted bentonite (GB). Baseline GB dispersion rheological model was developed using the concept of the effective volume fraction of particles, which depends on hydrodynamic forces. The model considers the effects of the three most significant factors, namely concentration, shear rate, and temperature. GB was then tested in a coreflood to ensure effectiveness and applicability in real reservoir conditions. Coreflood results were matched using a numerical simulator and the rheology model was incorporated to reduce uncertainty and determine critical GB-related simulation parameters. Subsequently, a pilot-scale simulation, which uses the history-matched coreflood parameters, was built to predict and optimize 5-spot pattern performance. A sensitivity analysis was performed for the effect of GB volume injected, layer thickness, and permeability contrast. The results show that the viscosity equation resulting from the modeling allows appropriate correlation of the experimental data of shear stress versus shear rate with change in concentration and temperature. The simulation results reveal that the injection of GB has improved pilot-scale performance in both water-cut reduction and oil recovery. Sensitivity results indicate that the effective period of GB treatment is longer when treated in low water cut than in high water cut. However, more GB injection results in better water control.

Three-dimensional morphometric analysis and statistical distribution of the Early Kimmeridgian Hanifa Formation stromatoporoid/coral buildups, central Saudi Arabia

The high porosity and permeability stromatoporoid/coral facies partly characterize some of the most productive supergiant Late Jurassic carbonate reservoirs in the Middle East. Reservoir models often overlook detailed morphology and distributions of this facies due to the limited resolution of subsurface data. 3D morphological architecture and distribution of the Late Jurassic stromatoporoid/coral buildups are poorly understood as not many studies specifically investigate these aspects. This study performs a full three-dimensional outcrop investigation of the stromatoporoid/coral complex part of the Late Jurassic Hanifa reservoir analog in Wadi Birk, Saudi Arabia. We investigated spatial correlation, clustering tendencies, scaling relationships, and comprehensive statistical description over a 1.2 × 1 km area analog to a small-scale sectoral model of a typical Middle Eastern oilfield. This study utilizes integrated datasets including measured sections, drone-based digital outcrop model (DOM), core, ground penetrating radar (GPR), and shallow seismic to perform a full three-dimensional outcrop investigation. We identify and map three levels of the scaling hierarchy of the buildups: S1, S2, and S3. S1-scale buildups (a few meters in length) combine to form S2 clusters (∼35 m in length), which in turn may grow into larger S3 complexes (∼128 m in length). S1-scale buildups are near-circular and isotropic. However, as the S1 buildups cluster and grow into S2 and S3, their circular shape evolves into pseudo-ellipsoids with a strong preferential orientation towards northwest-southeast. The S2 and S3-scale amalgamated buildups are associated with asymmetric flank accumulation towards the northwest. We propose that the orientation of the S2 and S3-scale buildups and associated flanks are attributed to hydrodynamic currents driven by paleo-trade winds. This study also performs a brief static connectivity assessment to demonstrate the subsurface implications of these facies to field development planning. Results show that a vertical 5-spot pattern with a 1 km spacing can, in the best case, only access 14% of the Gross Rock Volume of the build-up facies due to the extreme lateral heterogeneity. Some 84% of the build-ups would be connected via flank and other facies with significantly different reservoir quality. This result underlines the extreme heterogeneity of the late Jurassic shallow-water platform carbonates and the potential for substantial quantities of bypassed hydrocarbons remaining in subsurface analog reservoirs.

Assessment of chemo-mechanical impacts of CO2 sequestration on the caprock formation in Farnsworth oil field, Texas

This study evaluates the chemo-mechanical influence of injected CO2 on the Morrow B sandstone reservoir and the upper Morrow shale caprock utilizing data from the inverted 5-spot pattern centered on Well 13-10A within the Farnsworth unit (FWU). This study also seeks to evaluate the integrity of the caprock and the long-term CO2 storage capability of the FWU. The inverted 5-spot pattern was extracted from the field-scale model and tuned with the available field observed data before the modeling work. Two coupled numerical simulation models were utilized to continue the study. First, a coupled hydro-geochemical model was constructed to simulate the dissolution and precipitation of formation minerals by modeling three intra-aqueous and six mineral reactions. In addition, a coupled hydro-geomechanical model was constructed and employed to study the effects of stress changes on the caprock’s porosity, permeability, and ground displacement. The Mohr–Coulomb circle and failure envelope were used to determine caprock failure. In this work, the CO2-WAG injection is followed by the historical field-observed strategy. During the forecasting period, a Water Alternating Gas (WAG) injection ratio of 1:3 was utilized with a baseline bottom-hole pressure constraint of 5500 psi for 20 years. A post-injection period of 1000 years was simulated to monitor the CO2 plume and its effects on the CO2 storage reservoir and caprock integrity. The simulation results indicated that the impacts of the geochemical reactions on the porosity of the caprock were insignificant as it experienced a decrease of about 0.0003% at the end of the 1000-year post-injection monitoring. On the other hand, the maximum stress-induced porosity change was about a 1.4% increase, resulting in about 4% in permeability change. It was estimated that about 3.3% of the sequestered CO2 in the formation interacted with the caprock. Despite these petrophysical property alterations and CO2 interactions in the caprock, the caprock still maintained its elastic properties and was determined to be far from its failure.

An ANN model to predict oil recovery from a 5-spot waterflood of a heterogeneous reservoir

Waterflooding is a secondary oil recovery technique in which water is injected into an underground oil reservoir to maintain the reservoir pressure and boost oil recovery. The performance of a waterflood depends on several factors such as reservoir heterogeneity, reservoir fluid properties, flood pattern, etc. Most of the models developed to predict waterflood performance are either for linear systems or involve simplified assumptions for non-linear systems. In this study, we propose a novel, artificial neural network (ANN) model comprised of two hidden layers with 256 neurons each for the performance prediction of a 5-spot pattern waterflood in a heterogeneous reservoir at and beyond water breakthrough. The proposed model can be applied to estimate movable oil recovery efficiency of the waterflood (RFM) as a function of Dykstra-Parsons permeability variation coefficient (V), mobility ratio (M), permeability anisotropy ratio (kz/kx), production water cut (fw), a simple indicator of wettability (WI), and oil/water density ratio (DR) within reasonable accuracy. The MAPE of the proposed model was ∼4% and ∼5% using training and testing data, respectively. Our ANN model recommendation is based on a detailed comparative study against other popular soft computing models, such as adaptive neuro-fuzzy inference system (ANFIS) and support vector regression (SVR). Based on the accuracy and computational efficiency, the ANN model outperforms ANFIS and SVR. AIC and BIC of the proposed ANN model were also the lowest among all applied soft computing tools. The proposed model is tested on two real field cases and compared with a semi-analytical model and an empirical correlation. The presented model shows good agreement with the real field data. The trained ANN model, proposed here, saves computational time in forecasting the waterflood performance compared to a reservoir simulator.

Pilot-scale production and in-situ application of petroleum-degrading enzyme cocktail from Alcanivorax borkumensis

Petroleum degrading enzymes can be used as an alternative way to improve petroleum bioremediation approaches. Alcanivorax borkumensis is an alkane-degrading bacteria that can produce petroleum degrading enzymes such as alkane hydroxylase and lipase. In this study, pilot-scale Alcanivorax borkumensis fermentation was developed for producing large volumes of petroleum degrading enzymes cocktail (∼900 L). Different process conditions, such as inoculum age 72 h and size 4% v/v, temperature 30 ± 1 °C, agitation speed at 150 rpm and, fermentation period 3 days were determined as the optimum for producing alkane hydroxylase and lipase activity. The oxygen transfer capacity was studied for obtaining better bacterial growth and higher enzyme activities in bioreactor process optimization as well as scale-up. Results showed that the maximum values of oxygen mass transfer coefficient (kLa), oxygen uptake rate (OUR), oxygen transfer rate (OTR), alkane hydroxylase, lipase, and cell count were 196.95 h−1, 0.92 mmol O2/L/h, 1.8 mmol O2/L/h, 222.49 U/mL, 325 U/mL, and 8.6 × 1010 CFU/mL, respectively. Compared with the bench-scale bioreactors, the 150 L fermenter showed a better oxygen transfer rate which affected the cell growth that doubled the number and enzymes production that increased. Then, the enzyme cocktail was used for a field test in a diesel source zone using a 5-spot well pattern. The results showed a significant reduction in concentrations of C10 – C50 (from 36% to > 99%) after one injection of enzyme cocktail, mainly for the contaminated soils located in the saturated zone of the unconfined aquifer. This study confirmed the scaling-up ofalkane-degrading enzyme production to an industrial-scale and its application for effective bioremediation of petroleum contaminated sites.

Data-Driven Modeling Approach to Predict the Recovery Performance of Low-Salinity Waterfloods

Low-salinity waterflooding (LSWF) has, in the past decade, attained a lot of attention to enhance oil recovery. In LSWF, diluted water is injected into an oil reservoir to improve oil recovery. The injected low-saline water changes the wettability of the reservoir, which leads to higher oil recovery. The recovery of an oil reservoir can be predicted from simulators, which are tedious, expensive, and time-consuming. Therefore, there is a need for a simple, quick, and inexpensive substitute to predict the oil recovery factor for low-salinity waterfloods. This paper presents a novel empirical correlation based on a feed-forward neural network to predict LSWF recovery efficiency in a heterogeneous reservoir at and beyond water breakthrough. The proposed model is valid for a broad range of dimensionless input parameters—degree of dilution of high saline water, mobility ratio, degree of reservoir heterogeneity, permeability anisotropy ratio, API gravity, and production water cut. The new empirical correlation was developed using 20,000 simulated data points obtained from simulation results to cover a wide range of input values. The LSWF simulation model was developed and validated with a model of a real carbonate reservoir located in the Madison formation in Wyoming. The artificial neural network (ANN) model parameters were optimized by conducting extensive sensitivities of ANN parameters (hidden layer neurons, training algorithms, and transfer functions). Moreover, an interesting trend analysis was conducted to validate the physical behavior of the ANN model, and a comparison with the unseen dataset was performed. To evaluate the performance of the newly developed correlation, three statistical indices were used, including the average absolute percentage error (AAPE). AAPE was 1.69% and 1.84% for the training and testing datasets, respectively. The proposed ANN model is limited to a single-stage, low-saline waterfloods for a 5-spot pattern.

PENINGKATAN PRODUKSI LAPANGAN “M” DENGAN PENDEKATAN SIMULASI UNTUK MENENTUKAN SKENARIO PENGEMBANGAN MENGGUNAKAN METODE WATERFLOODING

Reservoir simulation is an area of reservoir engineering in which computer models are used to predict the flow of fluids through porous media. Reservoir simulation process starts with several steps; data preparation, model and grid construction, initialization, history matching and prediction. Initialization process is done for matching OOIP or total initial hydrocarbon which fill reservoir with hydrocarbon control volume with volumetric method.To aim the best encouraging optimum data, the plant of developments of this field was predicted for 22 years( until December 2035). The Scenario consisted of five different variation. First one is basecase, second scenario is scenario 1 + workover, third scenario would be scenario 1 + infill wells, fourth scenario is scenario 1 + peripheral injection, and the last fifth scenario is scenario 1 + 5-spot injection pattern wells. From all of the scenarios planned, recovery from from each scenario varied, the results are 31.05% for the first scenario, 31.53%, for the second one, 34.12%, for the third, 33.75% for the fourth scenario, and 37.04% for the fifth scenario which is the last one.Keywords: reservoir simulation,reservoir simulator, history matching

Forecasting evolution of formation water chemistry and long-term mineral alteration for GCS in a typical clastic reservoir of the Southwestern United States

Groundwater chemistry and rock properties can change dramatically following CO2 injection in a geologic sequestration system. A favored target for subsurface sequestration is clastic reservoirs, due to their limited tendency to impact water quality or porosity and permeability due to dissolution or precipitation compared to carbonate reservoirs. However, most clastic reservoirs will exhibit geochemical changes, especially during the injection phase and over the long term. And, in most oil reservoirs targeted for enhanced recovery and concomitant CO2 storage, water-alternating-gas, or so-called “WAG” injection schemes are preferred to maximize CO2 mobility and minimize viscous fingering of CO2. Under WAG schemes, reactive transport processes and resulting water quality changes and rock property changes may differ when compared to continuous CO2 injection (CCI) schemes.The purpose of this paper is to analyze and quantify the extent of geochemical changes to both water chemistry and rock properties, specifically for the “low hanging fruit” of CO2 storage targets: a sandstone formation using a WAG injection scheme. Specifically, the objectives of this study are: (1) to evaluate the evolution of formation water chemistry and mineral alteration induced by WAG injection in a typical southwestern U.S. sandstone reservoir; (2) to quantify CO2 trapping mechanisms and associated porosity and permeability evolution over the long term following injection; (3) to investigate whether different injection schemes (WAG vs. CCI designs) may affect the evolution of water chemistry and mineral alteration during the injection phase. Because it is not just a candidate formation, but rather is already undergoing CO2 injection for enhanced oil recovery (EOR) and sequestration, the Morrow Sandstone Formation in the Anadarko Basin of Texas was selected as representative of a typical clastic CCS candidate. A numerical reactive transport model of a 5-spot well pattern in the Morrow Formation was developed and used to simulate WAG injection and subsequent geochemical processes. Initial conditions of flow and geochemistry were based on actual measurements from the Morrow Formation within the Farnsworth EOR field in northern Texas. The simulation design period included WAG injection for 25 years (injection phase) followed by 975 years of post-injection monitoring (arbitrary post-injection phase). Simulation results suggest that formation water chemistry (pH, aqueous species Ca2+, Mg2+, Fe2+, HCO3−) dramatically changes after CO2 arrival, and mineral dissolution (with an increase in porosity and permeability) is greatest near the injection well during the injection phase. The simulated increase in porosity is approximately 2.7%, with a maximum permeability increase of almost 8.4% at the end of the injection phase. The possibility of halite mineral precipitation, a phenomenon observed in many injection scenarios, was specifically examined. However, no simulations yielded halite precipitation. Mineral precipitation increases in the long term (hundreds of years), resulting in both increased CO2 trapping by mineralization as well as decreased porosity and permeability.Finally, the analysis of impacts of WAG injection during the injection phase suggests that the extent of CO2-rock geochemical interactions following WAG increases compared to CCI scenarios. Specifically, the extra water injected (in WAG) facilitates aqueous reactions compared to CCI, which “dries out” the formation. Changes in porosity and permeability for CCI schemes are much less than those for WAG schemes, a factor to consider with respect to how these different schemes may impact injectivity.

Process, mechanism and impacts of scale formation in alkaline flooding by a variable porosity and permeability model

In spite of the role of alkali in enhancing oil recovery (EOR), the formation of precipitation during alkaline-surfactant-polymer (ASP) flooding can severely do harm to the stratum of oil reservoirs, which has been observed in situ tests of oil fields such as scale deposits found in oil stratum and at the bottom of oil wells. On the other hand, remarkable variation of stratum parameters, e.g., pore radius, porosity, and permeability due to scale formation considerably affects seepage flow and alkaline flooding process in return. The objective of this study is to firstly examine these mutual influential phenomena and corresponding mechanisms along with EOR during alkaline flooding when the effects of precipitation are no longer negligible. The chemical kinetic theory is applied for the specific fundamental reactions to describe the process of rock dissolution in silica-based reservoirs. The solubility product principle is used to analyze the mechanism of alkali scale formation in flooding. Then a 3D alkaline flooding coupling model accounting for the variation of porosity and permeability is established to quantitatively estimate the impact of alkali scales on reservoir stratum. The reliability of the present model is verified in comparison with indoor experiments and field tests of the Daqing oil field. Then, the numerical simulations on a 1/4 well group in a 5-spot pattern show that the precipitation grows with alkali concentration, temperature, and injection pressure and, thus, reduces reservoir permeability and oil recovery correspondingly. As a result, the selection of alkali with a weak base is preferable in ASP flooding by tradeoff strategy.

Feasibility and mechanism of compound flooding of high-temperature reservoirs using organic alkali

Abstract The technical feasibility of using organic alkali instead of an inorganic one during alkaline/surfactant/polymer (ASP) flooding in a heterogeneous reservoir under a high temperature of 95 °C in China was investigated. Laboratory experiments were performed to evaluate the alkali consumption, adsorption, and retention in formation and its formation damage. Also viscosity of the ASP compound flooding system, oil/water interfacial tension, and chromatographic separation were investigated. A comparison of results obtained through organic alkali with those obtained from inorganic alkali was conducted to evaluate the flooding effect of this system, and the mechanism of increasing recovery ratio was analyzed. Experimental results indicated that the consumption and dynamic adsorption of ethanolamine and formation damage observed through the organic alkali were significantly lower than those observed through the inorganic alkali. When compounded with the surfactant, ethanolamine could further decrease the oil/water interfacial tension. Moreover, ethanolamine exerted a protective effect on the surfactant, thereby decreasing adsorption loss. A flooding experiment with a 5-spot pattern was performed on a heterogeneous reservoir. Findings revealed that the organic ASP (OASP) compound flooding system achieves good displacement effects and mobility control even under high temperature conditions and significantly improved recovery ratios. As such, the proposed method is feasible for compound flooding in high-temperature reservoirs. The mechanism of OASP compound flooding was discussed to provide a theoretical basis for optimizing compound flooding systems for high-temperature heterogeneous reservoirs.

Large scale CO2 storage with water production

Abstract CO 2 storage without water production is realized by injecting CO 2 into the underground without any actions for relieving the pressure buildup generally associated with such an operation. Successfully storing large volumes of CO 2 at a given site with no active pressure relief is not guaranteed due to uncertainty of the size and permeability of the hydraulically connected complex connecting to the gas injectors. With water producers active pressure management is possible, and the volume of produced water liberates corresponding pore volume that is available for storage of CO 2 without any pressure buildup. Also the relevant size of the storage complex is mainly confined to the region between the injectors and producers, thus reducing the amount of uncertain geology involved. In this paper we run 144 generic 5-spot well pattern Eclipse simulations to assess the effect of petrophysical and operational input parameters. It is seen that storage efficiency and gas breakthrough times can be relatively sensitive to the input parameters, highlighting some of the challenges when a planning a real large scale CO 2 storage project. It is also seen that that the 5-spot storage pattern is quite efficient for gas storage, ranging from 9.7% to 62.5% reservoir volume gas per effective pore volume stored at gas breakthrough in the water producer

Experimental Investigation of Polymer Adsorption-Induced Permeability Reduction in Low Permeability Reservoirs

The polymer retention during polymer flooding causes reduction in pore throat size which can be detrimental to oil recovery. Especially, in low permeability reservoir unlikely in high permeability system, EOR effect of polymer flooding would not excel comparing to water flooding because of the polymer adsorption onto grain surface. This phenomenon is more significant as higher concentration of polymer solution is injected. In this study, we investigated oil recovery process during polymer flooding for a quarter of 2D 5-spot pattern of low permeability sandstone slab, in which the injected polymer solution flows in different shear rates corresponding to streamlines. The results showed that the ultimate recovery was 1.9 times higher in concentration of 1,000 ppm case than 0 ppm. The polymer adsorption layer formed during the flooding reduced the effective permeability of 1,000 ppm polymer solution. Therefore, it facilitated the oil flow and the stage of water-cut reaching 99% was slackened off.

Simulation study of CO2 sequestration potential of the Mary Lee coal zone, Black Warrior basin

Significant potential exists for CO2 sequestration in coalbed methane reservoirs of the Black Warrior basin. Reservoir simulation is an appropriate approach to estimate both the storage capacity and methane recovery enhancement. However, prior to a reliable reservoir modeling and simulation, conducting an accurate and comprehensive reservoir characterization study is necessary. The purpose of the present study is twofold: (a) to provide a rigorous reservoir characterization study required for modeling Mary Lee coal group in the Blue Creek field of the Black Warrior basin; (b) to run fluid flow simulations to predict the performance of ECBM process applied to an under pressured zone of the Mary Lee coal group. According to the current well configuration of Blue Creek field, three applicable well patterns, namely a direct line drive, an inverted 5-spot and a normal 5-spot were separately (i.e., in three distinct cases) used for simulating ECBM. Simulations were run on an approximately 32 ha (80-acre) drainage area, and included coal matrix shrinkage/swelling effects. The injected gas was assumed to be pure CO2. Using an inverted 5-spot pattern, simulations predicted that after 7.5 years of CO2 injection, approximately 32,000 tonnes of CO2 would be sequestered per 32 ha of this zone and that methane recovery would be enhanced by 36 %. Using a normal 5-spot pattern, CO2 breakthrough would occur 2.4 years earlier, and about 40,000 tonnes CO2 would be sequestered. However, methane production would be enhanced by 33 %. Considering methane recovery enhancement, direct line drive pattern delivered poor results in comparison with two other patterns. As expected, the results also showed that CO2 injection would increase water production.

A new method for rapid productivity estimation of 5-spot well pattern

Abstract Under the requirement of well pattern estimation for low-permeability reservoirs, horizontal wells and fracturing wells, this paper presents a new method for 5-spot well pattern productivity estimation by introducing shape factor of the drainage area, equivalence radius of fracture/horizontal well and threshold pressure gradient. By applying mirror image and principle of pressure superposition, steady-state flow for an infinite well net can be transformed into pseudo steady-state flow for a producer or an injector in a closed drainage area. This new productivity estimation method for 5-spot well pattern can be unified with a general formula considering the type of well pattern, type of injection-production, type of well completion and type of reservoir. Application in the Yushulin Oilfield showed that the new method presented in this paper is easy to derive, to calculate and to extend. It can be used to estimate the productivity rapidly in oilfields.

Steam Injection in Oil Reservoirs With Bottom Water Zone

3-D scaled model was used to study the performance of steam injection in reservoirs having a bottom water zone with the application of different well configurations. 3-D laboratory model was designed to represent ¼th of a 5-spot pattern in the B. Kozluca field in Turkey. Four experiments were conducted with the rectangular model with or without bottom water zone. The well configurations were changed during the course of experiments to determine their effects on oil recovery. Bottom water thicknesses were changed to see the effetcs on oil recovery. The physical properties of crushed limestone and crude oil mixture were kept constant during the experiments. Steam was injected through a vertical injection well in the model. Strings of thermocouples were used to observe 3-D temperature distribution. The maximum oil recovery was obtained by placing the horizontal producer along the diagonal of the rectangular model. Vertical injection-horizontal production well configuration provided better oil recovery than other well configuration even in the presence of a bottom water zone. Oil recoveries decreased with an increase in the thickness of the bottom water zone. Steam-oil ratio (SOR) increased in the presence of bottom water zone.

Simulation Studies of Steam-Propane Injection for the Hamaca Heavy Oil Field

Abstract Simulation studies were performed to evaluate a novel technology, steam-propane injection, for heavy Hamaca crude oilfrom Venezuela's Orinoco Basin. The oil has a specific gravity of 1.005 (9.3 ° API) and a viscosity of 25 Pas (25,000 cp) at 50 ° C. Two types of studies were performed: a simulation study to history-match laboratory results and a reservoir simulation study of steam-propane injection in a 5-spot pattern. A 1D 48 grid-cell model was used to describe the sand mix in the injection cell. A ten pseudo-component oil model for Hamaca oil was developed based on composition up to C10 that gave a satisfactory history match of experimental results. Components in the C7 - C10 range appear to play a significant role during steam-propane injection and therefore need to be described in greater detail. The pseudo-component oil model was subsequently used in the reservoir model. The reservoir model represented a symmetry volume that is one-eighth of a 10-acre 5-spot pattern. A 9 ? 5 ? 10 3D Cartesian model was used to describe the symmetry volume, with one axis (x-axis) oriented parallel to the injector-producer direction. Simulation results indicate the following. First, oil production acceleration of 15﹪ was observed with a propane-steam mass ratio (PSR) of 0.05 compared to pure steam injection. A substantial gain in discounted revenue and savings in steam injection cost would be realized. Second, unlike the experimental results, the oil production rate peak with steam-propane injection, 175 m3/d (1,100 STB/D), is significantly higher than that with pure steam injection, 110 m3/d (690 STB/D). Third, oil production acceleration increases with increasing propane content. And finally, oil recovery (at the end of the five-year forecast period) increases from 2.3﹪ OOIP for pure steam injection to 7.0﹪ OOIP for steam-propane injection with a PSR of 0.05. Both experimental and simulation studies indicate that steam-propane injection is a very promising technology. Further research, followed by field tests, are recommended to better understand and verify the process under actual field conditions. Introduction In 1991, Butler and Mokrys(1) described a variation of the steam-assisted gravity drainage (SAGD) called VAPEX. Propane is injected with steam into a horizontal well, forming a vapourfilled chamber within the reservoir. The vapour dissolves in the oil around the chamber and the oil drains by gravity to a horizontal producer near the bottom of the reservoir. Subsequent work by Butler and Mokrys(2, 4) showed VAPEX resulted in partial in situ de-asphalting and a reduction of heavy metals in the produced oil. The resulting oil can be of a higher quality and better suited for direct refining. The basic mechanisms of steam injection with additives are z thought to be swelling of the oil, viscosity reduction, and solution gas drive. It is observed that the additives tend to exist primarily at the boundary of the steam chamber where they expand the size of the steam chamber but lower the steam temperature (because of partial pressure effects). It is also in this region where significant partitioning into the oil and water phases occurs.

In Situ Biodegradation of High Explosives in Soils: Field Demonstration

The first field pilot-scale demonstration of a technology for in situ remediation of vadose zone soils contaminated with high explosives (HEs) has been performed at the Department of Energy's Pantex Plant. The HEs of concern at the demonstration site were hexahydro-1,3,5-trinitro-1,3,5-triazine (RDX) and the 2,4,6-trinitrotoluene (TNT) metabolite 1,3,5-trinitrobenzene (TNB). Concentrations ranged from 70 ppm, above the (prior to 1999) risk reduction clean-up criteria of 2.6 and 0.51 ppm, respectively. The shallow (<10 m depth) soils at the site could not be excavated due to the presence of buried utilities. Based on previous laboratory studies, it was found that the contaminated soils had indigenous microbial populations that could be stimulated to degrade the RDX and TNB anaerobically. A 5-spot well pattern with injection at the central well and extraction at the four outer wells (each 4.6 m from the injection well) was used to flood the target vadose zone soils with nitrogen gas with the intent of stimulating the activity of the HE degraders. The system was monitored periodically for gas composition as well as HE concentrations and microbial activity in retrievable soil samples. After 295 days of in situ treatment, the average target HE concentrations were approximately one-third lower than the initial site averages. Operation of the pilot-scale treatment system continues.

A Comparative Laboratory Analysis of Steamflooding With Horizontal Wells In Heavy Oil Reservoirs With Bottom Water Zone

Abstract Two laboratory 3D scaled models were developed to compare the performance of steam flooding in reservoirs having bottom water zone with the application of different well configurations. One of the models was triangular, designed to represent 1/12th of a 7-spot pattern and the other was a square that corresponds to ?th of a 5-spot pattern in the B. Kozluca field in Turkey. Nine experiments were conducted by using the triangular model with or without bottom water zone, whereas four experiments were conducted with the rectangular model. The well configurations were changed during the course of experiments to determine their effects on oil recovery. Bottom water thicknesses were changed to see the effects on oil recovery. The physical properties of crushed limestone and crude oil (12.4 ° API) mixture were kept constant during the experiments. Steam was injected through a vertical injection well in both models. Strings of thermocouples were used to observe 3D temperature distribution inside the models. The maximum oil recoveries were obtained by placing the horizontal producers along the hypotenuse of the triangular model and the diagonal of the rectangular model, respectively. Besides, in both cases, the same well configuration provided better oil recovery than any other well configurations even in the presence of a bottom water zone. Oil recoveries decreased with increase in the thickness of the bottom water zone. SOR increased in the presence of bottom water. Introduction The increasing demand of non-renewable fossil fuel energy and the gradual depletion of conventional crude oil reservoirs led to the development of heavy oil reservoirs. The most efficient means to recover oil from these heavy oil reservoirs is thermal recovery method in which heat is applied to the reservoir. The application of heat in the form of hot water, hot gases, and steam reduces the viscosity of these heavy oils upon which, a more economic recovery is readily obtainable. These days, the thermal recovery method is widely known and applied worldwide for secondary and tertiary recoveries. Of all the thermal recovery methods, steam injection is the most popular method. Following steam injection into any heavy oil reservoir, the viscosity, specific gravity and flow resistance of the fluid in the reservoir changes, resulting in oil production increases. The reduction in the viscosity as a result of an increase in the temperature, facilitates the movement of the heavy oil. Advantages of Horizontal Wells Because of their numerous advantages, horizontal wells have gained attention in the petroleum industry(1,2).Horizontal wells provide larger contact within a reservoir and hence, eliminate the need for multiple vertical wells to acquire same reservoir drainage. Recovery is two to five times greater than that of a non-stimulated vertical well.In the case of a reservoir where vertical penetration of the formations would be uneconomical, drilling of the horizontal well would render a sufficient well bore opening and a possibility of a more economic recovery.Horizontal wells in the reservoir where coning of water and gas are predominant provide a better oil recovery while minimizing the coning effects.

PREDICTIVE MODEL STUDIES OF MISCIBLE GAS FLOODING OF NIGERIAN UNDERSATURATED CRUDE OIL RESERVOIRS

ABSTRACT A CO2 predictive model has been used to assess the viability of CO2 miscible processes in two Nigerian crude oil reservoirs. These reservoirs designated ND-1 and ND-2 contain undersaturated 22°API of oil with an initial pressure of 2200 psia at 5100ftss. From the study, approximately 19% and 25% OOIP oil recoveries equivalent to gross CO2 requirements of 0.216 and 0.281 STB of oil/MCF of CO2 were predicted respectively for ND-1 and ND-2 reservoirs at WAG ratio of 1.0 and total fluid injection rate of 1500 bbl/d on a 124.2 acres 5-spot pattern. These predictions compare favourably with values which have been reported for successful field projects.

TERTIARY OIL RECOVERY POTENTIAL FROM CO2-MISCIBLE FLOODING OF AGBADA VISCOUS OIL RESERVOIR

A mathematical model has been employed to determine the incremental oil recoverable by CO2-miscible processes in Agbada viscous oil reservoir at assumed abandonment conditions. Sensitivity of the recoverable oil to changes in water-alternating-gas (WAG) ratio, fluid injection rate and pattern area was also assessed. The results showed a potential for tertiary recovery of up to 28% OOIP at WAG ratio of 1.0 and fluid injection rate of 2,000 bbl/d on an 800 metre, 5-spot pattern spacing.