Early work characterized the relationship between initial oil (Soi) and residual oil saturation to waterflood (Sorw) and recent work has investigated theoretical oil recovery in transition zones. This study details experimental results for shallow-shelf carbonate lithologies and explores model application in thin carbonate reservoirs, such as those of the Midcontinent U.S., where production is often primarily from the transition zone.
Understanding Soi, Sorw, and relative permeability (kr) in transition-zone dominated reservoirs is fundamental to understanding recovery, and planning and managing IOR and EOR operations in these reservoirs. Drainage and imbibition oil-water relative permeability measurements were performed on Pennsylvanian-age oomoldic limestones and Mississippian-age moldic porosity mudstone to grainstone lime-dolomites. For these rocks, Sorw increases with increasing Soi due to enhanced trapping by emplacement of oil in fine pores. The Land-defined trapping characteristic, C, increases with increasing porosity resulting in less trapping with increasing porosity. This relationship, coupled with increasing "irreducible?? water saturation (Swrri) with decreasing porosity and permeability, results in a systematic increase in Sorw with decreasing porosity/permeability and Soi. As Soi decreases with depth in the transition zone, proper modeling of kr requires a family of kr curves that reflect changes in kr with changing Soi. Utilizing a family of kr curves in recovery analysis shows that both oil and water recovery are greater than predicted from models utilizing kr curves with a constant Soi and Sorw. Oil recovery is higher because Sorw(Soi) is lower and water recovery is higher because Sw increases with proximity to the oil-water contact and as Sorw(Soi) is lowered.
These results validate and expand on use of the Land equation in shallow-shelf carbonates and help to explain both the high oil recovery and the high water production rates that are often evident in these reservoir systems.
The productivity of most gas condensate wells is reduced significantly due to condensate banking when the bottom-hole pressure falls below the dew point. The liquid drop-out such gas wells leads to reduced gas relative permeability and thus to low recovery problems. An understanding of the characteristics of the high-velocity gas-condensate flow and relative permeabilities is necessary for accurate forecast of well productivity. In order to tackle this goal, a series of relative permeability measurements on a moderate permeability carbonate core, using a binary retrograde condensate fluid sample were conducted near miscible conditions. The experiments used a pseudo-steady-state technique at high pressure and high velocity, measuring relative permeability under conditions similar to the near well region of a carbonate gas-condensate reservoir. Furthermore, the flow of gas and condensate at different force ratios (capillary and bond numbers) are investigated. It was observed that relative permeability depended on fluid composition and flow rate as well as condensate and water saturations. It was observed that as the flow rate of wetting phase (condensate) increased or the interfacial tension decreased, relative permeability curves shifted to left. It was found that a simple three-parameter mathematical model that depends on a new dimensionless number called condensate number successfully models the gas-condensate relative permeability data. The developed model resulted in a good agreement with published gas-condensate relative permeability data as well as end point relative permeabilities and saturations.
The well was a sidetrack in an existing well. A window was milled in the 9-5/8" casing from 4,124 ft to 4,211 ft. A 7-5/8" 29 lb/ft liner was run through the milled window and the casing shoe set at a depth of 7,820 ft. The initial 6-1/2" open hole was plugged back from 7,525 ft to 8,125 ft due to the amount of shale that was encountered during drilling operations. An open hole sidetrack was performed and TD on the open hole section was reached at 12,137 ft.
Numerous examples of dependency of waterflood efficiency on brine composition have been observed for sandstones. Improved oil recovery depends on complex crude oil/brine/rock (COBR) interactions. Elucidation of the circumstances and mechanisms of increased oil recovery still requires extensive laboratory testing. Special attention is being given in laboratory and pilot tests to increased recovery by injection of low salinity brine in both secondary and tertiary modes. Investigation of connate brine composition as a key variable has been extended to variation in initial water saturation (Swi). Mixed-wettability (MXW) cores were prepared by aging with crude oil at reservoir temperature for a range of initial water saturations.
Oil recovery as % original oil in place (OOIP) generally increased with initial water saturation for secondary recovery by injection of low salinity brine. CS crude oil/Berea sandstone combinations were essentially insensitive to displacement with low salinity brine in secondary mode even when the injection pressure was double that for oil recovery by injection of reservoir brine (RB). However, significant increase in tertiary mode (about 6% OOIP) was observed for the same COBR combination when low salinity brine was injected after establishing residual oil by injection of reservoir brine.
Low salinity brine floods with Minnelusa oil and 400 md Berea sandstone showed more than 13% OOIP increase in recovery over that given by flooding with reservoir brine. For the Minnelusa oil, however, very little additional oil was produced in tertiary mode. From available data, response to injection of low salinity brine in tertiary mode was clearly highest for reservoir rock and crude oil. Overall, rock properties are the most important factor in improved recovery by injection of low salinity brine.
Abs t ra ct Inj ection of a p H-sen s itiv e p o l ym er in to a h e terog e n e o u s reservo i r as a n o v e l d e ep -p en etrating m o b ility co n t ro l m e th od has been pr o p o se d earl i e r ( A l - Anazi a nd Sha r m a 200 2b).
Weyburn oil field, located in southeast Saskatchewan, is the location of one of the largest CO2 flooding projects in the world since September 2000.
In this paper, data of the past performance of waterflooding in the Weyburn field was used to develop empirical correlations to predict the performance of CO2 flooding. Two different correlations were developed based on CO2 injection schemes in Weyburn. The first correlation is based on a WAG process through vertical wells, and the second correlation is based on the cases in which CO2 is injected through horizontal wells and water is injected separately through vertical wells. As the first step, production data from 1958 to 2004 were collected and analyzed. Oil production rates for both waterflooding and CO2 flooding periods, water injection rates, and CO2 injection rates were used in developing the correlations. The empirical model for injecting CO2 and water through vertical wells was verified using the Kinder Morgan CO2 Scoping Model and actual field production data. The comparative analysis showed 12% error between our simple correlation and the Kinder Morgan model. For injecting CO2 in horizontal wells, the correlation could not be verified against the Kinder Morgan model, but the correlation followed the actual oil production in the field very closely.
This new model can be used effectively as a screening tool for predicting the performance of CO2 flooding in various locations in the Weyburn reservoir based on the data obtained from past waterflooding performance and the rate of CO2 injection. Hence, it can contribute significant savings in time and expense to the operating oil company. Also, this approach can be utilized for other potential CO2 flooding processes in reservoirs with histories and properties similar to those of the Weyburn field.
Blanchard, Vincent (Institut Francais du Petrole) | Lasseux, Didier (LEPT - ENSAM) | Bertin, Henri Jacques (LEPT - ENSAM) | Pichery, Thierry Rene (Gaz de France) | Chauveteau, Guy Andre (Institut Francais du Petrole) | Tabary, Rene (Institut Francais du Petrole) | Zaitoun, Alain (Institut Francais du Petrole)
The mechanism of Disproportionate Permeability Reduction (DPR) resulting from polymer or gel adsorption in porous media has been widely reported in the literature in the domain of Darcy regime. However, very few studies have been dedicated to the impact of polymer adsorption in porous media when two-phase flow occurs in non-linear regimes which are of interest in a wide range of applications. The objective of this paper is to report some experimental investigations on the effect of polymer adsorption on gas-water flow at low mean pressure, i.e. when Klinkenberg effects (or gas slippage) must be considered, as well as at high flow rates when inertial effects are significant.
The experimental study reported in this paper consists of water and nitrogen injections into various silicon carbide model granular packs having different permeabilities. More specifically, the purpose is to investigate gas flow at different water saturations before and after polymer adsorption over flow regimes ranging from slip flow to inertial flow. In good agreement with previous works, in the Darcy regime, we observe an increase in irreducible water saturation and a strong reduction in the relative permeability to water while the relative permeability to gas is slightly affected. At low mean pressure in the gas phase, the magnitude of Klinkenberg effect is found to increase with water saturation in the absence of polymer, whereas, for the same water saturation, the presence of an adsorbed polymer layer reduces this effect. In the inertial regime, a reduction of inertial effects is observed when gas is injected after polymer adsorption, taking into account water saturation and permeability modifications. Experimental data are discussed according to hypotheses put forth to explain these effects.
Copyright 2006, Society of Petroleum Engineers This paper was prepared for presentation at the 2006 SPE/DOE Symposium on Improved Oil Recovery held in Tulsa, Oklahoma, U.S.A., 22-26 April 2006. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members.
Carbonate reservoirs become more water-wet during thermal recovery. The effect of temperature on wettability-altering process is caused by contribution from several parameters involving fluid/fluid and fluid/rock interactions. This paper aims at describing the interrelationship between different parameters of a simple oil/water/rock model over temperature range of 25 to 130 degree centigrade.
Saturated and unsaturated fatty acids as well as naphthenic acids with saturated and unsaturated rings are selected for this work to alter the water-wet calcite surface. The type of selected acids is based on the distribution of these components in reservoirs in the Norwegian continental shelf.
Contact angle measurements on the treated calcite surfaces are used as indication of wattability alteration. At fluid/fluid interface the interfacial tension and distribution of the solutions of n-decane /fatty acids /water systems are measured at elevated temperature. A set of experiments is also performed in order to understand the role of the temperature on fluid/rock interface by zeta potential measurements.
As the temperature increases, calcite surface becomes more water-wet. The obtained results at fluid/fluid interface (IFT and distribution coefficients) and contact angle measurements show that the trend of decrease in contact angles with temperature follows the same trend as IFT and distribution coefficients, specifically if one divides acids to saturated and unsaturated separately. Electro-kinetic measurements (zeta potential) of calcite surfaces with temperature demonstrate that increasing temperature reduces surface charge to less positive, which may enhance the repulsive forces between dissociated acids and calcite surface. Due to this change in surface charge, the adsorption of acids on the surface becomes less effective at high temperatures; hence wettability of the calcite surface tends to be more water-wet.
Keywords: Wettability alteration; Carbonate; Temperature; IFT; distribution coefficients; surface charge
The wettability of a hydrocarbon reservoir depends on how and to what extent organic components are adsorbed to the solid phase's present. For carbonate reservoirs naphthenic acids and number of carboxylic acids are recognized to be the most frequent acidic components that adsorbed on the surface and altered the wettability.[2-5] The degree to which the wettability is altered by these components is determined by several parameters. Temperature is one of those controlling parameter that has an effect on both oil/water and water/mineral interfaces. Many authors have reported a shift in wettability of mineral surfaces toward water-wet at elevated temperatures.[6-9] Increasing the solubility of adsorbed materials from surfaces and decreasing the IFT are two different effects of temperature on wettability at elevated temperature. Several work have directed to the partition coefficients of carboxylic acids between oil and water phase as a function of pH and salinity and to perhaps a lesser extent on the effect of temperature.[10-13]. Hamouda et al. have performed an extensive experimental work on wettability alteration of calcite surfaces due to dissolved carboxylic acids in oil phase at ambient temperature and different pHs. It was shown that there is a possible implication between change in IFT and partitioning with the wettability of the calcite surfaces. They showed that the high soluble acids in water owing low partitioning coefficients hence lesser effect on IFT has minor change on wettability alteration of calcite surfaces. Increasing pH decreased the IFT between water/n-decane /fatty acid systems as well as partition coefficients of acids from oil to the water phase. Consequence of those changes resulted in decrease in contact angles on calcite surfaces. These behaviors were explained by possible increase in the repulsive forces due to dissociation of acids at water/n-decane interface hence change in the surface charge of calcite surface.
Depending on the oil composition, both decreasing and in some cases increasing in IFT with the temperature were reported in literatures.[6-7,14] In terms of partition coefficients it has been shown insignificant effect by the temperature.[11,15]
Parker, Mike (Kerr-McGee) | Bradford, Robert N. (El Paso Production) | Corbett, Laurence Ward (Schlumberger) | Heim, Robin Noel (Schlumberger) | Isakson, Christina Leigh (Schlumberger) | Broome, Steven S. (Schlumberger Oilfield Services) | Proano, Eduardo
Well placement decisions are routinely made on the basis of simulation models that are created before production operations begin. Real-time downhole pressure data and surface flow rate information can provide a significant set of calibration information early in the life of the reservoir. In this paper we describe a method for comparing a set of assumed reservoir parameters, especially the presence of a connected aquifer and its size, with a set of simulation models to assist with well placement decisions.
In the South Timbalier 316 block, a delineation well penetrated the steeply dipping B4 reservoir near the oil/water contact. Based on a comparison of downhole pressure data, with data from simulation models, the operator concluded that a connected aquifer was present and estimated its size. This information was sufficient for the operator to know that the well would not be needed as a water injector and to justify a sidetrack from the downdip location to an updip location.
When the updip sidetrack well was drilled, reservoir rock quality was below the minimum for a commercial completion. This brought into question the viability of any hydrocarbon storage capacity in the northern portion of the field. As soon as the updip sidetrack well was logged, a "what-if?? reservoir model was run to simulate a no-hydrocarbon-reservoir scenario in the northern portion of the field. This reduction represented approximately 25% of the reservoir hydrocarbon pore volume. The model results clearly indicated that this was not a reasonable model and gave the operator confidence to sidetrack the well directly to the west, to a slightly downstructure position, whereby a successful completion was made. Without this "quick-response reservoir model?? the well may have been sidetracked to the south, resulting in a less-than-optimal well location.