Laboratory studies show the existence of some strains of bacteria in field crude oils and formation waters. This work is concerned with studying the effect of indigenous bacterial activities on the relative permeability of samples from Egyptian fields. Such study is an original contribution to the knowledge of microbial enhanced oil recovery.
Phase volume studies were carried out using two types of crude oils having different spores forming bacteria. The relative permeability experiments were conducted in sandstone cores. Some available nutrient solutions being used in the field tests were also used.
Based on the phase volume measurements, it was found that the indigenous microbial growth was better after two days incubation time with 1% molasses concentration as a nutrient. Residual oil saturation was found to decrease with stimulating the indigenous bacteria in the crude oils by using 1% molasses concentration. Presence of 1% molasses concentration increases the relative permeability to oil. It was found also that crude oil A, which contains Clostridium sp. and Bacillus sp., gave better relative permeability curve behavior than that of crude oil B, which contains Bacillus sp. only. Salinity increase decreases the relative permeability to oil. In the presence or absence of molasses, no clear trend of absolute permeability on oil-water relative permeability curves was observed.
The results obtained are discussed and analyzed in terms of the system phase variation, interfacial forces, wettability characteristics, hydrogen ion concentrations, viscosity effects, and mechanical and mineralogical analysis of the cores.
The earliest realization that certain microbes might be useful for enhancement of petroleum recovery was made in 1926, when Beckman1 proposed that certain bacterial metabolites would assist in the release and transport of oil in the geological structure. Subsequent laboratory and field studies2-6 have shown that microorganisms can produce effective products similar to those described for chemical and miscible EOR processes. These products can assist in the release of oil from the capillary pores and can improve the sweep and displacement efficiencies so that: (1) the microbial production of gases can improve the flow characteristics, (2) the microbial production of solvents can reduce the interfacial tension, (3) the microbial production of organic acids can result in the dissolution of carbonates in source rock and increase the rock permeability, (4) The microbial production of polymers can increase the viscosity of the water in the waterfloods and/or plug the high-permeability zones of the reservoir rock and thus divert the reservoir fluids to previously unswept areas of the reservoir, (5) and the microbial production of surface active compounds (surfactants) can reduce oil-water interfacial tension and cause emulsification, and can alter the wettability of the reservoir rock. Also, the microbial growth on rock pore surfaces can plug the high-permeability zones. Another important discovery is the ability of certain bacteria to eliminate paraffin deposition around the producing wells. During the last ten years, several studies on the microbial characteristics and metabolic activity of bacteria for improve oil recovery in the middle east area have been carried out.7-13 Based on these studies, MEOR should be able to recover up to 30 % of the residual oil under reservoir conditions.
Injection of either carbon dioxide (CO2) or nitrogen (N2) can serve as an effective method for enhanced recovery of coalbed methane. In this paper, we provide new analytical solutions for flow of ternary gas mixtures. The adsorption/desorption of the components to/from the coalbed surface is approximated by an extended Langmuir isotherm, and the gas phase behavior is predicted by the Peng-Robinson EOS. Langmuir isotherm coefficients are used that represent a moist Fruitland coal sample from the San Juan Basin of Colorado. In these calculations, mobile liquid is not considered. Given constant initial and injection compositions, a self-similar solution that consists of continuous waves and shocks is found. Mixtures of CH4, CO2, and N2 are used to represent coalbed and injection gases. We provide examples for systems in which the initial gas has a high CH4 content, and binary mixtures of CO2 and N2 are injected. Injection of N2-CO2 mixtures rich in N2 leads to relatively fast initial recovery of CH4. Injection of mixtures rich in CO2 gives slower initial recovery, increases breakthrough time and decreases the injectant needed to sweep out the coalbed. The solutions presented indicate that a coalbed can be used to separate N2 and CO2 chromatographically at the same time CBM is recovered.
Coalbeds have large internal surface area and strong affinity for certain gas species such as CH4 and CO2. In coalbed methane (CBM) reservoirs, most of the total gas exists in an adsorbed state at liquid-like density. Only a small amount of the total gas is in a free gas phase. Primary recovery using depressurization techniques induces desorption of the CBM by lowering the overall pressure of the reservoir. On the other hand, enhanced recovery of coalbed methane (ECBM) by injecting a second gas maintains overall reservoir pressure, while lowering the partial pressure of the CBM in the free gas. Injected gas also sweeps the desorbed gas through the CBM reservoir. Nitrogen is a natural choice as an injection gas because of its availability. Carbon dioxide, on the other hand, is also promising because of the additional benefit of greenhouse gas sequestration. When combusted, methane emits the least amount of CO2 per unit of energy released among all the fossil fuels. Therefore, synergy exists between CO2 sequestration and production of methane that leads to greater utilization of coalbed resources for both their sequestration ability and energy content. The first application of ECBM by CO2 injection has been carried out in the San Juan Basin, and proved to be technically and economically feasible1.
One important aspect of ECBM is the adsorption and desorption behavior of gas mixtures on coalbeds. A significant amount of work has been invested on this issue as it is related to coal mine safety2-11. However, transport of the desorbed gas through coalbeds has not been examined in detail. Arri et al.12 studied the primary recovery of a single sorbing component and ECBM by nitrogen injection. In this paper, we extend the analysis to consider systems with three components. Besides CH4, coalbeds may contain significant amounts of CO2, N2 and other gas species. An average coal-bed gas is composed of approximately 93 percent CH4, 3 percent CO2, 3 percent wet gases, and 1 percent N213. Further, when flue gas, a primary source of greenhouse gases, is used for ECBM and CO2 sequestration purposes, the injection gas may contain more than two components. The exact composition of the flue gas depends on the combustion temperature and percentage excess air at different levels of moisture content in the fuel14. In this study, we focus on the interaction of CH4, N2 and CO2.
Surjaatmadja, Jim B. (Halliburton Energy Services, Inc.) | McDaniel, B.W. (Halliburton Energy Services, Inc.) | Cheng, Alick (Halliburton Energy Services, Inc.) | Rispler, Keith (Halliburton Energy Services, Inc.) | Rees, Matthew J. (PetroCanada Oil and Gas) | Khallad, Abe (PetroCanada Oil and Gas)
Abstract This paper discusses a relatively new acid-stimulation process that uses dynamic fluid energy to divert flow into a specific fracture point in the well, which can initiate and accurately place a fracture. The acid-stimulation process often uses two independent fluid streams: one in the pipe and one in the annulus. With this process, two different fluids can be mixed downhole with high energy to form a homogenous mixture.
Four such treatments in four openhole, horizontal wells were performed in one formation. The first well was acidfractured with coiled tubing to replace many small fractures along the open hole. The second well was acid-fractured with coiled tubing, but downhole mixing concepts were used to provide in-situ generation of CO2 foam. Fewer, yet larger, fractures were placed in this well. The third and fourth wells were treated with acid using rotating and nonrotating jetting tools while mixing the acid with CO2 downhole. Many small, near-wellbore fractures were expected in these wells.
Investigating the mechanism that may have contributed to these successes in the field is important. Laboratory tests were performed to analyze the jetting mechanism exposed to rock. The findings of these tests are reported in this paper.
Successful well treatment depends on identifying the causes of the production deficiency for the specific well to be treated. Production deficiencies and treatment options include debris, filter cake or near-wellbore damage, deep damage close to the wellbore, wellbore location, and low formation permeability. If the production problem is caused by debris plugging along the wellbore, the well can be cleaned with an effective hydrablasting and cleaning service. This service generally combines a sound design software, specialized fluid systems, and a wash tool designed for the different mechanics associated with vertical, deviated, and horizontal wells. If near-wellbore damage is causing the production deficiency, an acid wash might be the best solution.
If deep damage close to the wellbore is decreasing production, an operator can place several small fractures to bypass the damage. Such small fractures increases the effective wellbore diameter. If the wellbore is located in a poorly producing zone in the reservoir some distance from a better interval in the reservoir, or if a vertical permeability barrier exists, the operator may need to create larger fractures that can communicate the wellbore with more productive zones. If the average permeability of the formation is too low to produce at commercial levels, placing numerous hydraulic fractures (proppant fractures or fracture acidized) is the only viable method for effective production stimulation. Of course, successful treatments should improve production at the lowest possible cost. Therefore, engineers must consider economics (cost/benefit ratio) when choosing a production enhancement solution.
This paper addresses the use of dynamic diversion and downhole mixing as an effective tool to resolve all of the above situations, particularly carbonate acid treatments, by offering effective acid placement, fracture acidizing, and fracture acidizing with squeeze as needed for the well.
THAI - ‘Toe-to-Heel Air Injection' is a new, short-distance displacement process, that achieves high recovery efficiency by virtue of its stable operation and ability to produce mobilised oil directly into an active section of the horizontal producer well, just ahead of the combustion front. THAI, therefore, avoids the pitfalls inherent in most conventionally operated in situ combustion (ISC) processes, which employ vertical injection-vertical producer wells to achieve long-distance displacement. However, the problem of achieving efficient ignition and start-up still requires critical attention, in order to ensure optimal process operation.
A series of 3-D tests on heavy Wolf Lake crude (10.5 °API) and Athabasca Tar Sand Bitumen (8 °API) were made using well configurations: vertical (VI) or horizontal injection (HI) and horizontal producer (HP) wells in direct line drive (VIHP, HIHP); staggered line drive (VI2HP) and line drive (2VIHP). Experimentally, the horizontal injector configuration (HIHP) was found to be the most efficient for achieving rapid start-up, i.e. the shortest time to achieve stable combustion front propagation. However, injection of air via a horizontal well is not a very practical design for field operation. The single vertical injector configuration (VI2HP) was slow to achieve stable operation, due to the development of a much smaller ignition zone, initially, compared with the HIHP configuration. When hot air was used for ignition, the time delay for oil production is related to the reservoir temperature. When the initial temperature in the sandpack was 15°C, then a vertical injector, placed high in the sandpack, combined with a horizontal producer well (VIHP) achieved slower start-up than VI2HP for post-steam flood THAI, with the initial sandpack at 100°C. All of the tests achieved very high oil recoveries, averaging greater than 80% OOIP, except in the VIHP test. The recovery in the latter case was only 70% OOIP due to the loss of air injectivity during later stages of the combustion. Significantly, THAI also preserves the very substantial thermal upgrading which occurs in the mobile oil zone, averaging an increase of 6 to 8 API points.
Key words: In Situ combustion, Air injection, Heavy oil recovery, Downhole upgrading, THAI, Horizontal wells, Well combinations, Short-distance oil placement.
The three natural oil recovery mechanisms include solution gas drive, gas cap expansion drive, and water drive. Water or gas injection drives are known as secondary recovery methods. Enhanced Oil Recovery (EOR) is usually considered to apply at the tertiary stage, but can also be applied as primary or secondary methods.
For light oil reservoirs, the ultimate oil recovery by conventional methods can reach up to 50%, or more, using water injection. However, for highly viscous oils, comparable recoveries would only be about 5% to 15%, and essentially zero in the case of extremely viscous oils, or bitumen.
The main objective of an EOR process is to achieve high oil recovery and high production rate. The low recovery for heavy oil is mainly due to its high viscosity, i.e. too viscous to flow to the producer wells at rates sufficient to support an economic operation. Thermal EOR methods are required for heavy oil production. Thermal EOR processes are achieved by injecting a hot fluid (steam), or air for combustion, with the aim of increasing the reservoir temperature to reduced the viscosity of the heavy oil1,2. Because of the dramatic effect of temperature on heavy oil viscosity, more oil is mobilised at a higher temperature and is capable of being displaced.
In this paper, we extend to three fluid phases a prior finite-element study of hydraulic conductance of two-phase creeping flow in angular capillaries. Previously, we obtained analytic expressions for the hydraulic conductance of water in corner filaments. Here we present the results of a large numerical study with a high-resolution finite element method that solves the three-phase creeping flow approximation of the Navier-Stokes equation. Using the projection-pursuit regression approach, we provide simple analytic expressions for the hydraulic conductance of an intermediate layer of oil sandwiched between water in the corners of the capillary and gas in the center. Our correlations are derived for the oil layers bounded by the concave or convex interfaces that are rigid or allow perfect slip. Therefore, our correlations are applicable to drainage, spontaneous imbibition, and forced imbibition with maximum feasible hysteresis of each contact angle, oil/water and gas/oil. These correlations should be useful in porenetwork calculations of three-phase relative permeabilities of spreading oils. Finally, we compare our results with the existing correlations by Zhou et al., and Hui & Blunt, who assumed thin-film flow with an effective film thickness proportional to the ratio of the average, our correlations are two-four times closer to the numerical results than the corresponding correlations by Zhou et al., and Hui & Blunt.
Since direct measurement of flow of three immiscible fluids is very difficult, the pore-scale models of three-fluid systems2,5,12,13,17 have blossomed. One of the more important advancements in such models was the approximation of single pore geometries as angular capillaries with square or arbitrary triangular cross-sections. Although real pores are not exactly square or triangular, this approximation allows one to capture the flow of water in the pore corners and the flow of oil and gas in the pore center. As illustrated in Figure 1a, when three fluids are moving in a single angular capillary, the most wetting fluid (water or Fluid 1) resides in the corner and the most nonwetting fluid (gas or Fluid 3) fills the center. The third fluid (oil or Fluid 2) forms an intermediate layer sandwiched between the other two fluids. In some cases of large contact angles and positive spreading coefficients, we may find more than one sandwiched layer, Figure 1b. These intermediate layers are a few micrometers thick and have been observed in micromodel experiments.3,11,16,21 It is drainage through these oil layers that is responsible for the high oil recoveries seen experimentally.4,10,23 Although it was initially thought that only spreading oils could form such layers in angular pores, it has been theoretically predicted and experimentally verified that nonspreading oil can also form intermediate layers in the crevices of the pore space.3,11,25 Therefore, the formation of sandwiched layers is not only related to the positive spreading coefficient, but also depends on the curvatures of the o/w and g/o interfaces, the corner geometry and the contact angles.5
Creeping flow of oil in these intermediate layers is the subject of this paper. In particular, we study the hydraulic conductances of oil flow in stable fluid layers of different sizes and geometries. We provide simple and accurate correlations for these conductances by relating them to the interface geometry, fluid contact angles, and pore geometry. The proposed correlations should be useful in pore network calculations of three-phase relative permeabilities.
This paper presents a new approach for the simulation of fractured or partially fractured reservoirs with a general-purpose reservoir simulator.
In many fractured reservoirs, fractures could be found in limited zones or "sweetspots". Hence, not all parts of the reservoir will typically require dual porosity or dual permeability treatment. The method presented in this paper allows creation of dual porosity or dual permeability cells wherever the attributes of the fracture geological model suggest to do so. The remaining - unfractured - part of the model can be treated like conventional single porosity areas. This approach will be called adaptive dual continuum. As a result, the generated simulation grid block models will resemble the real geological situation more closely than any other modeling approach. This will result in maximum reliability of the simulation model and allow better estimation of recovery for the various recovery processes modeled.
All fracture and matrix-fracture transfer properties are derived from the geological information and fracture intensity. The simulator - that applies an unstructured gridding method - will store them on a cell by cell basis. The paper will discuss the new workflow from generating the geological model by combining the strengths of continuous and discrete models, thereby achieving a high level of data integration until the consistent data export into the reservoir simulator.
The adaptive dual continuum approach was successfully implemented into a commercial reservoir simulator and several examples will prove the capability of this reservoir modeling approach for accurate and economic simulation of fractured or partially fractured reservoirs.
Natural or induced fractures play a crucial role in many petroleum reservoirs. Even though only a small percentage of toady's reservoir models explicitly describe the fractures, one may claim that practically most petroleum reservoirs are fractured (or partially fractured). Hence, one of the first questions to be raised is whether or not existing fractures are important for the reservoir behavior under producing conditions. In other words, what is contribution of the flow in fractures to the overall fluid flow? Are the fractures connected to each other and in this way forming a fracture network?
Posing this question to a petrophysicist, to a geologist or to an engineer, one can expect different views and answers. As far as the reservoir engineer is concerned, only fractures and fracture networks that affect fluid transportation to and from the wells are of significance. Only when there are fractures with sufficient length of penetration through the reservoir rock, fractures that are interconnected and with sufficient density or spacing, their effects can be observed and measured under dynamic flow conditions.
To assess fracture contributions accurately, a wide range of geological, petrophysical and engineering methods are applied. These methods apply to a large variety of different scales.
The paper will assume that those investigations result in a reservoir that is characterized by - at least some - fractures that are significant for fluid flow and that the reservoir model must account for the fracturing in one way or the other.
During the course of this paper an attempt is made to classify the type of fractures encountered in the respective reservoir. After a brief discussion on those fracture types, the paper will investigate the significance of the spatial (lateral or vertical) distribution of the fractures. The following questions must be asked in order to build a representative reservoir model: Are the fractures equally distributed or spaced? Is the fracture intensity and orientation approximately constant across the entire reservoir or are there some (important) areas that appear to be unfractured? As a result of those questions, one should be able to select the proper set of modeling and simulation tools. The paper will give a brief overview of available simulation and modeling approaches for fractured reservoirs leading to the definition of a new and flexible tool, the so called Adaptive Dual Continuum method.
A new type of surfactant has been developed that can be used at very low concentrations to produce ultra-low interfacial tensions (IFT) for sandstone and limestone formations. These surfactants can be used for Alkaline Surfactant Polymer (ASP) floods, surfactant floods and as an adjuvant for water floods. These new types of surfactants differ from traditional surfactants used in ASP and surfactant floods by offering the following advantages:
Low concentration levels - They are effective at low concentration levels normally used for ASP but do not require alkali to produce low interfacial tensions in sandstone formations. For limestone formations, sodium carbonate is normally preferred to reduce adsorption however it is not needed to produce ultra-low IFTs.
Salt tolerance - They are very salt tolerant. Case studies using this new type surfactant in brines with ~110,000 PPM total dissolved solids (TDS) and ~2500 PPM divalent cations show excellent interfacial tension lowering, even at 0.05% surfactant levels. The injection water does not need to be treated or softened, which can result in a tremendous cost saving for IOR applications.
Emulsion, corrosion, and scale reduction - Problems such as emulsion formation, scale, corrosion, etc. are minimized because only low concentrations of surfactant are needed and alkali is not required to produce ultra-low interfacial tensions.
Examples and data using the new surfactants in both limestone and sandstone applications with various crude oils and brines are presented.
The chemical process of Improved Oil Recovery (IOR) utilizing surfactants has been suggested, used and proven successful for over 50 years. The surfactant reduces the interfacial tension between the brine and residual oil and therefore increases the capillary number. The capillary number (Nc) is used to express the forces acting on an entrapped droplet of oil within a porous media. Nc is a function of the Darcy velocity (?) exerted by the mobile on the trapped phase, the viscosity (µ) of the mobile phase, and the IFT (s) between the mobile and the trapped oil phase. Equation (1) below shows the relationship of the Darcy velocity, viscosity and IFT to the capillary Number.
A capillary number of about 10-6 is found after the typical water flood and this number mustbe increased by at least two to three orders of magnitude in order to efficiently displace the oil. The IFT between the oil and water during and following water flooding is in the range of 101 to 100 mN/m. The use of the proper surfactant can be easily lower the IFT to 10-2 mN/m or less which increases the capillary number by at least two to three orders of magnitude.
Gas-condensate reservoirs suffer losses in well productivity due to near wellbore condensate dropout when the flowing bottomhole pressure declines below the dew point pressure. To alleviate the problem, pressure maintenance and gas cycling are common practices for developing gas condensate reservoirs.
A study has been conducted to investigate the applicability of one-time produced gas injection in removing the condensate bank around the wellbore and thereby restoring well productivity. The study focused on two major issues: the optimum time of commencing gas injection and the optimum volume that will remove the condensate bank permanently and restore well productivity. The practice will accelerate the production rate per well and maximize the ultimate hydrocarbon recovery.
Three gas-condensate fluid samples with maximum liquid dropout in the range of 6 %, 11 %, and 21 % were used. The benefit of the method was investigated using a full-field compositional reservoir simulation model of a gas condensate field.
Reservoir simulation results indicated that, for the lean gases, the best time of starting the gas injection was when the average reservoir pressure around the producing well fell below the maximum liquid dropout pressures. For the rich gas, however, gas injection starting at average reservoir pressure above the maximum liquid dropout pressure resulted in better recovery.
The study showed that one-time gas injection not only restored the well productivity and increased reserves but also accelerated the recovery process. These findings bring a different perspective to the development and management of gas condensate reservoirs.
The productivity of wells in gas condensate reservoirs often decreases rapidly as the reservoir is depleted. The decrease is ascribed to a ring of condensate around the wellbore that grows with production time. The ring develops because the flowing bottom hole pressures drops below the dew point pressure of the reservoir gas1. Simulation studies and laboratory studies have indcated condensate saturation near the wellbore as high as 70%. A number of independent investigations have consistently shown that liquid dropout around the wellbore has been the primary reason for losses in well productivity. The presence of liquid around the wellbore reduces the effective permeability to gas2-5. The condensate occupies the gas flow channels and thus impedes gas flow6.
The aim of this study has been to assess the impact of a once-off injection of gas in removing the condensate bank and reclaiming well productivity. Whilst condensate dropout translates into losses of revenue due to valuable hydrocarbon components being left in the reservoir, the main focus of the well intervention method is to restore productivity and increase recovery of gas.
Single well models have been useful in understanding the phenomenon of condensate dropout or, indeed, in assessing the impact of remedial actions. Nevertheless, they still come short of accurately predicting behaviour on a full field scale. Most single well models are homogeneous or have simplistic reservoir properties and dimensions, in exchange for short simulation time and less complexity in setting them up.
In this study, the proposed method was tested on a full field model of a North Sea field.
Key questions pertain to timing of the initiation of the gas injection in the life of the reservoir and to determining the gas volumes to achieve maximum benefit. The study was also aimed at establishing the range of applicability of the method by investigating gas condensate fluids with a range of maximum condensate dropouts.
Traditionally, the addition of a non-condensable gas to steam is known to have a beneficial effect on heavy-oil production when conventional vertical wells are used. Little information and experimental evidence exists regarding the effect of the addition of such gases in the steam assisted gravity drainage (SAGD) process. The limited literature suggests that the addition of small amounts of such gases (e.g., carbon dioxide) may improve oil recovery. The gas accumulates at the top of the reservoir and provides a thermal and pressure insulation effect that in turn limits the rate of front spreading at the corners of the steam chamber.
In order to investigate these phenomena, SAGD experiments with and without carbon dioxide injection were conducted in a physical model. It is packed with crushed limestone premixed with a 12.4° API heavy-oil. Temperature, pressure and production data as well as the asphaltene content of the produced oil were monitored continuously during the experiments. It was observed that for small well separations as the amount of carbon dioxide increased, the steam condensation temperature and the steam-oil ratio decreased. The heavy oil became less mobile in the steam chamber due to lower temperatures. Thus, the heating period was prolonged and the cumulative oil recovery as well as the recovery rate decreased. In this instance, the produced oil contained a relatively high concentration of asphaltenes. This supports the observation of poorer oil recovery as the fraction of carbon dioxide injected increased. A large asphaltene fraction in mobile oil serves to maintain high viscosity. On the other hand little or no change in oil recovery and oil recovery rate was observed for larger well separations regardless of the fraction of carbon dioxide in the injection gas. Similar behavior was observed when n-butane was injected along with steam instead of carbon dioxide. The impact of initial gas saturation (carbon dioxide or n-butane) was also investigated. It was observed that cumulative oil recovery, rate of oil recovery, and steam-oil ratio decreased independent of well separation compared to a reservoir with no initial non-condensable gas.
Gravity drainage of heavy oils is of considerable interest to the oil industry. Because heavy oils are very viscous and, thus, almost immobile, a recovery mechanism is required that lowers the viscosity of the material to the point where it can flow easily to a production well. Conventional thermal processes, such as cyclic steam injection and steam assisted gravity drainage (SAGD) are based on thermal viscosity reduction1. Cyclic steam injection incorporates a drive enhancement from thermal expansion. On the other hand, SAGD is based on horizontal wells and maximizing the use of gravity forces2. In the ideal SAGD process, a growing steam chamber forms around the horizontal injector and steam flows continuously to the perimeter of the chamber where it condenses and heats the surrounding oil. Effective initial heating of the cold oil is important for the formation of the steam chamber in gravity drainage processes3. Heat is transferred by conduction, convection, and by the latent heat of steam.
The heated oil drains to a horizontal production well located at the base of the reservoir just below the injection well. Butler et al.4 derived Eq. (1) assuming that the steam pressure is constant in the steam chamber, only steam flows in the steam chamber, oil saturation is residual, and heat transfer ahead of the steam chamber to cold oil is only by conduction. One physical analogy of the above process is that of a reservoir where an electric heating element is placed horizontally above a parallel horizontal producing well.
Kumar, Rajesh (Oil & Natural Gas Corporation Ltd.) | Cherukupalli, P.K. (Oil & Natural Gas Corporation Ltd.) | Lohar, B.L. (Oil & Natural Gas Corporation Ltd.) | Chandra, Dinesh (Oil & Natural Gas Corporation Ltd.)
The conventional and widely used way of distributing saturation arrays inreservoir simulation models is through porosity-weighted water saturationvalues. In this way, each grid cell has an assigned porosity and initial watersaturation. The porosity and water saturation are estimated with the help ofwell logs using established procedures. However, for producing reservoirs, logderived saturations may not represent initial saturations due to variousreasons like depletion due to production and effect of water injection etc. Oneof the ways to estimate the initial water saturation is by the use ofrelationship between depth and bulk volume of water (BVW). Such relationship,known as Saturation-Height function is used to estimate saturation values awayfrom the well locations and to calculate the hydrocarbons in placevolumetrically. This approach has been used in a multi layered carbonatereservoir of an Indian offshore field.
Layer-wise saturation height functions are developed by establishingrelationships between height above the free water level and bulk volume ofwater derived from the wells drilled in the initial phase of field development.The scatter in the BVW plot has been reduced by further classifying the datafor different porosity facies. These porosity intervals are treated as rocktypes for that layer. Since each layer has a particular range of porosity,different porosity based rock types are identified. Height above the free waterlevel versus water saturation plots are then generated for different rock typesusing the relationship developed for each geological layer.These equations wereused to assign initial water saturation in the reservoir simulation model.
The distribution of water saturation within a 3-D reservoir model is a keytask of an integrated reservoir description. Possible ways of distributingwater saturation values to the various layers in a reservoir simulation modelare,
By mapping, so each grid cell has an assigned initial water saturation,calculated by integrating porosity-weighted water saturation values over themapped zone for each well. This entails the use of "pseudo capillary pressures"at each grid cell to maintain initial equilibrium.
By the use of relationship such as bulk volume of water (BVW) versus depthcurve. BVW has the added advantage of compensating to a certain extent fordifferent average porosity levels within comparable zones.
Initially, efforts were made to establish different rock types using coreanalysis based capillary pressure data. Fig. 1 shows the layer wisecapillary pressure versus water saturation plot. It is evident that it would bedifficult to identify different rock types for different layers as in eachlayer irreducible water saturation values cover a wide range and overlap withother layers. Therefore, In order to calculate saturation-height functionswithout using core measurements, an alternative method was adopted.
A significant amount of work to generate saturation height functions isavailable in the literature1-5. These functions calculates watersaturation based on one or more of the parameters like, porosity, oil watercontact, gas water contact, irreducible water saturation, height above contactetc. But, all these functions have their own merits and demerits. Saturationheight function based on bulk volume of water and height above the free waterlevel has also been reported in the literature6-7. A methodology foridentifying different rock types based on the variation of porosity in eachlayer in a multi-layered carbonate reservoir using saturation height functionconcept is discussed in the present paper.