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.
Reservoir simulation of steam injection into heavy oil sands of West Coalinga Field in California has been conducted to assess suitability of different permeability distributions generated from geological and fractal modeling processes. Permeability distributions in each model were derived by integrating stratigraphically controlled models with core data provided by Chevron Production Company. Three distinct distributions were generated for each lithologic group: facies tract, facies group, and a fractal distribution of the facies group. The grid design is based on stratigraphic architecture of depositional facies. Construction of these models involved application of advanced analytical property-distribution methods conditioned to continuous outcrop control for improved reservoir characterization.
Numerical simulation of steam injection into three adjacent 5 spot well configurations was used to assess suitability of each model. Injection and production histories of wells in the study area were simulated, including shutdowns and the occasional conversion of production wells to steam injection wells. The framework provided by the facies groups yielded a more realistic representation of reservoir conditions than facies tracts, which is revealed by a comparison of history-matching results. Permeability distributions obtained using the fractal model predict the high degree of heterogeneity within reservoir sands of West Coalinga Field. Modeling results indicate that predictions of oil production are strongly influenced by the geologic framework and by the boundary conditions.
Improved predictions of interwell reservoir heterogeneity have the potential to increase productivity and to reduce recovery cost for California's heavy oil sands, which contain several billion barrels of reserves in the San Joaquin Valley.
The West Coalinga oil field in California (Figure 1) produces from heavy oil sands of the Miocene Temblor Formation. The oil in this field has low API gravity (12º to 15º API) and is highly viscous at the 40ºF initial reservoir temperature. This makes the field an ideal candidate for enhanced oil recovery through steam injection. The field is shallow, multilayered and stratified with low reservoir pressure, varied rock permeability, and an average porosity of about 34%.
Steamflooding started in 1961, and Coalinga is the oldest steamflood operation in the state of California. Prior to 1960, only about 10% of the oil in place was produced, but with the advent of steam floods and horizontal drilling, recoverable oil potential has been increased up to approximately 60 to 70%.
West Coalinga field was chosen for this study because of the opportunity to relate continuous cores of the producing Temblor Formation to nearby outcrops of the same formation. Observations of lateral variability and vertical sequences in outcrop led to an improved understanding of the geological framework of the reservoir. In particular, detailed characterization of stratigraphic bounding surfaces in outcrops enabled identification of those same surfaces in cores and logs of the reservoir. The bounding surfaces were subsequently used as reference horizons in reservoir modeling.
The critical oil (or gas) rate to avoid coning of unwanted fluids into production wells is an important design parameter. Simulation methods are useful to predict critical rates in reservoirs with complex heterogeneities and boundaries, but they are manpower intensive and prone to errors when large grid blocks are used. Current analytical methods are quick and easy to use, but their assumptions are too restrictive. Thus, there is a need for improved analytical methods that can account for well patterns and more complex boundaries, and also serve as further benchmarks for simulation.
This paper makes analytical solutions more realistic by extending existing single-well analytical solutions to account for multiple wells and common no-flow and constant pressure boundary conditions. A potential function is derived to superimpose existing single well coning solutions for single- or simultaneous two-phase flow. Capillary pressure and relative permeability effects on coning are included. The only limiting assumptions are vertical equilibrium (VE) and steady-state flow.
Comparisons with simulation show good agreement in predicted critical oil rates when steady state and VE are approached. VE and steady-state are approximately achieved when aspect ratios are greater than about 10. Even when aspect ratios are less than 10, the predicted critical rates are useful in that they are always conservative. The proposed analytical solutions are quick and easy to use compared to reservoir simulation and can be used in the development of downhole water-sink technology (DWS).
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]
Compositional simulation is usually used to predict the performance of multi-contact miscible (MCM) recovery schemes. One key assumption in most such simulations is that of instantaneous compositional equilibrium is achieved between phases in each grid block. This is despite the fact that most grid blocks are tens of metres long and at least a metre thick.
This paper investigates the non-equilibrium observed in series of multi-contact miscible displacements performed in the laboratory. For simplicity a two-phase, three-component (IPA/water/cyclohexene) liquid system that exhibits an upper critical point at ambient conditions was used. Both vaporising and condensing drives were performed in well-characterised homogenous glass-bead packs. The use of analogue fluids and bead-packs enabled visualisation of the displacements as well as the usual measurements of effluent composition against time and recovery.
Non-equilibrium was observed in the effluent from both the condensing and vaporising experiments. This increased with flow-rate but appeared to be independent of the permeability and the length of the bead-pack. Further experiments investigating the influence of gravity on vertical displacements indicated that non-equilibrium may also be a function of the viscous to gravity ratio.
Detailed simulation using a commercial compositional simulator was unable to predict this non-equilibrium unless the results were tuned to the experimental observed effluent profiles using alpha factors. This is despite the fact that all PVT data, relative permeabilities and other pack properties were taken directly from experiments. However good match was obtained from a layered model with the permeability distribution obtained from a unit mobility ratio miscible displacement in the same pack.
These results are consistent with physical dispersion being the underlying cause of the non-equilibrium. Viscous fingering is discounted due to the low mobility ratio (~2) of the displacements.
The Cerro Dragon asset, located in the highly mature area of Golfo San Jorge Basin, Argentina, has around 30 producing structures; each one containing from 20 to 50 separate, highly heterogeneous, reservoir horizons, from 6 to 30 feet thick. From 1999 to 2005 proved reserves increased threefold and non proved reserves increased fourfold, moreover, oil production grew from 48,000 BOEPD to over 116,000 BOEPD, largely due to optimization and expansion of waterflood projects.
The aim of these projects was to increase the water injection rate from 248,000 BWPD to 714,000 BWPD along with the 1999 average of 5 reservoirs accessed per injector-well to an average of 12, with a maximum of 25, in 2005, keeping at the same time the highest possible control over the injected-water flow rate on each layer.
In an experimental process started in 2000, injector-well completions were designed and tested in several wells with different reservoir properties. The experience acquired with the analysis of these completions was used to improve them as well as to develop new ones. Today, this process continues, testing and enhancing new designs to fulfill the needs of the upcoming waterflooding projects.
This paper shows the experience acquired from 401 injector-well completions over the past 6 years, discuss the successes and problems encountered with each completion design under different reservoir conditions (i.e. differential pressures between layers). In addition, it contains information about the procedures and technology used to reduce the completion set up cost and to extend its useful life by solving leakage problems without replacing the completion installation.
The mayor achievement at this point of the process have been successfully running an injector-well completion of a total of 19 packers and 18 injector mandrels (with an average of 12 packers and 12 mandrels out of 48 completions ran on the first half of 2005).
The objective of this paper is to serve as a reference guide for injector-well completion designs in multilayered fields where a vertical expansion of the waterflooding projects is intended.
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.
Ansah, Joseph (Halliburton Energy Services Group) | Soliman, Mohamed Y. (Halliburton Energy Services Group) | Ali, Syed Afaq (Chevron Energy Technology Co) | Moreno, Carlos (Repsol YPF Ecuador Inc.) | Jorquera, Ricardo Alberto (Halliburton Energy Services Group) | Warren, John Michael (Halliburton)
For many years, operators and service companies have applied conformance treatments without adequate methods to verify treatment efficiency, since complexities of the treatment and reservoir systems have made attempts to quantify the effects of these conformance solutions with available tools unreliable. A comprehensive database had been developed with help of several operating companies of conformance treatments that were performed by several service companies over 30+ years. This database shows that in the absence of proper diagnostics and analysis, the success of a conformance treatment usually hovers around 50% even in well established areas. Application in new areas usually fares significantly worse, with a success ratio of 30% or less.
An important reason for this unacceptable situation is the tendency to design a conformance treatment without adequately considering reservoir effect. In this paper, we present a methodology and a numerical simulation approach that are aimed at improving the success ratio of conformance treatments.
Optimum conformance treatments must consider:
reservoir temperature and pressure effects, and
tracking of conformance fluid-property changes with time and temperature.
To adequately design a conformance treatment, it is important to predict both pressure and temperature profiles inside the wellbore and the reservoir. Using a numerical simulator that couples the wellbore with the reservoir provides a very efficient means for developing a methodology to optimize conformance treatments. Simulated examples are given to shed insight into basic conformance phenomena such as coning and channeling. Most importantly, two field cases are presented to demonstrate practical application of the developed methodology for designing an optimum conformance solution.
This new methodology reduces operational and economic risks associated with conformance treatments. It also allows for optimization of these treatments through more accurate prediction of water and hydrocarbon production.
The 3-D streamline simulation approach is complementary to finite difference simulation techniques. One of the main advantages of streamline simulation is its ability to display paths of fluid flow and to calculate rate allocation factors. These capabilities have been utilized to improve operating and development plans for a water-flood project.
An incremental development plan for a Saudi Arabian carbonate reservoir that included the drilling of several horizontal injection/production wells is discussed in this paper. A few wells had already been drilled at the start of this study. The main objectives of this study were to improve well placement and injection rates using streamline simulation.
During the course of the study a few limitations of the streamline simulator have been encountered, highlighted, and discussed. The results showed that streamline simulation is still in the development stage in highly compressible systems. It is tricky to follow field/group rate targets and limits along with the individual well rate targets in prediction mode.
Prior to the optimization phase of the study, the streamline simulator was successfully applied to reproduce the historical performance of the reservoir during primary depletion in the absence of any water injection.
Valuable information was obtained from streamline simulation; a) distribution of injected water to associated producers, b) water loss to the aquifer, c) percentage of oil produced due to each supporting injector, and d) amount of water cut attributable to each supporting injector.
Quality indicators were generated to gauge injection efficiency for each well using plots of injection rate vs. offset oil/liquid production rate. Relatively poor performance injectors were identified from this plot. Injection allocation rates and injector drilling locations were then modified through a series of simulations to improve their efficiency. This led to an improved injection pattern in the studied reservoir.