We earlier presented a proof for the model of Stone (1982) for gravity segregation in steady-state, horizontal gas-liquid flow in homogeneous porous media using only the standard assumptions of the method of characteristics. We extend this method here to cases of co-injection of gas and liquid over only a portion of the formation interval, injection of water above gas over the entire formation interval, and injection of water and gas in separate zones well separated from each other.
If gas and liquid are injected at fixed total volumetric rates, the horizontal distance to the point of complete segregation is the same, whether gas and liquid are co-injected over all or any portion of the formation interval. The volume of reservoir swept by gas may be affected by these different injection strategies, however, and is not directly predicted by our model. At fixed injection pressure, the deepest penetration of mixed gas and water is expected when fluids are co-injected along the entire formation interval.
At fixed total injection rate, injection of water above gas gives deeper penetration before complete segregation than does co-injection, but again exactly where the two fluids are injected does not affect the distance to the point of segregation. At fixed injection pressure, injection of liquid above gas is predicted to give much deeper penetration before complete segregation. When injection pressure is limited, the best strategy for simultaneous injection of both phases would be to inject gas at the bottom of the reservoir and liquid over the rest of the reservoir height, with the ratio of the injection intervals adjusted to maximize overall injectivity.
These results apply equally to gas-liquid flow and to foam. Sample computer simulations for foam injection agree well with the model predictions if numerical dispersion is controlled.
The Statfjord Formation in Gullfaks South was discovered in 1978, and came on production in 1999 as part of the Gullfaks Satellite Development.
In the Plan for Development and Operations (PDO) The STOOIP was estimated at 35 million Sm3, with estimated recoverable reserves of 12.6 million Sm3. Start up of the first two wells in 1999 showed that the production rate was lower than expected, most likely as a result of poor reservoir communication. A third well was drilled in 2001 and experienced gas breakthrough shortly after startup. Based on these observations booked reserves were reduced to 2.4 million Sm3 in the reservoir management plan for 2002.
Production has been limited by low connectivity, reservoir heterogeneity and gas breakthrough. Surface operated downhole inflow control and multilateral wells have been identified as solutions to these limitations, which has lead to an increase in expected oil recovery.
This paper describes the process of implementing Downhole Instrumentation and Control System (DIACS) and Multilateral Technology (MLT) in three horizontal subsea wells drilled in 2003 and 2004. This has led to a twofold increase in the reserve estimate to 5.4 million Sm3 in the reservoir management plan for 2005.
Because of low volumetric sweep efficiency and large difference in injection and production rate of each zone, the recovery factor of water flooding is very low in some continental and heterogeneous sandstone oil fields, especially when the reservoir continuity is poor, permeability low and high permeability variation between different zones. Due to the amount of incremental producible oil is not large enough to further drill infill wells economically, drilling infill wells and performing polymer flooding simultaneously was proposed and a pilot test has been concluded.
The paper introduces the laboratory studies on selection of polymer injection parameters and project design optimization. According to these studies, a pilot test of "Combining Small Well Spacing with Polymer Flooding?? was conducted. The well spacing is 100 meters, the zones with a thickness of less than 1 meter and with a permeability rage of 5 to 100 md were combined together and put on development. Both lab studies and pilot results show that the volumetric sweep efficiency was greatly increased, especially after applying separate zone injection measures in polymer injectors based on injection profile surveys and tracer test data. The pilot test indicates that the technique of combining infill wells with polymer flooding is economically feasible with 10% OOIP incremental recovery at a production cost of $10/bbl.
In continental, multilayer and heterogeneous sandstone oilfields, some reservoirs with poor connectivity and low permeability have lower recovery factors. The low degree of connection of layers between wells and inner-layer interferences lead to high watercut for waterflooding and poor effenciency for increasing the recoverable reserves of single wells. In order to further enhance the oil recovery and increase the oilfield's recoverable reserves, we drilled infill wellpatterns and performed polymerflooding simultaneously to improve the combined economic benefits of marginal reserovir. The main idea of the technology is to adjust the reservoir connectivity by drilling infill wellpatterns, and then inject a polymer solution. On the basis of waterflooding, polymerflooding could further increase some amount of recoverable reserves. The technology of combining dense wellpattern with polymerflooding will not only improve oil recovery but also obtain better economic benefits. Therefore, we implemented the pilot test in the oilfield and also applied separate-layer injection and stimulation measures during the test, which achieved good results with average incremental oil per day for a single well 1.83 times that of the original production, watercut decreased 10.2% and oil recovery increased more than 10%.
Full-field simulations have been successfully used to model reservoir development scenarios under water or WAG injection. When a reservoir is developed with regular patterns, reservoir engineers often build a type pattern model (TPM) and perform detailed, mechanistic, fully compositional simulation studies to understand displacement mechanisms. Simulation results from these mechanistic TPM studies are then scaled to full field to help design, develop, and manage the field waterflood or WAG injection projects. For a field developed with regular patterns, the scaleup of TPM results to the full field is quite straight forward; requiring identification and simulation of several different pattern types, followed by volumetric scaleup with tank models. However, when a field is developed with no regular patterns because of reservoir geology or other reasons, it is not clear how to apply the scaleup approach described above.
This paper presents a novel approach that uses simulation results from 2D (two dimensional) mechanistic models in conjunction with a full-field 3D waterflood study to describe the nonpattern field in a number of injector-producer segments. The approach also specifies the segment's initial pore volume (hydrocarbons and water), the injector, producer allocation factors, and recovery curves appropriate for the field development. For waterflood, the recovery curve is waterflood efficiency vs. cumulative water injected. For WAG floods, the additional recovery curve is EOR (oil incremental to waterflood) efficiency vs. cumulative solvent injected. Once the segment description with appropriate parameters is complete, it is straight forward to apply the tank model based scaleup approach to predict the full-field waterflood or WAG behavior. The paper presents the development and application of the new approach using example of a satellite field located on the North Slope of Alaska for a miscible WAG project.
Tank Model Scaleup Approach - Regular Patterns
Full-field simulations have been successfully used to model reservoir development scenarios under water or WAG injection.[1,2] However, accurate prediction of flood performance using traditional finite difference simulations requires extremely fine resolution in both the areal and vertical directions. Areal grids on the order of several acres are required to correctly predict breakthrough time and post-breakthrough waterflood performance. Capturing the EOR recovery mechanisms require even finer grids with vertical resolution on the order of a couple of feet to properly describe the character of the miscible gas flood. For a large scale miscible gas project, fully compositional full-field reservoir simulation is not practical.
In order to help design, develop, and manage the Prudhoe Bay Miscible Gas Project (PBMGP), the authors used a tank model scaleup approach, in which rigorous, fully compositional simulations are done only for a few typical patterns. The miscible project area, PBMGM, in reference 3 is developed with regular, inverted nine spot patterns (Figures 1, 2).
In this paper effluent data from laboratory experiments are compared with analytical composition routes and profiles for three-phase partially miscible flow of three-component mixtures. Core flood experiments were run in vertical glass bead packs to achieve approximately one-dimensional displacements with stable displacement fronts. The displacements employed in this study include modest effects of dispersion, but dispersion does not substantially alter the composition routes.
Complex analytical composition routes are developed by the method of characteristics (MOC) for one-dimensional, dispersion-free flow where up to three partially miscible flowing phases may be present. The exponents used in the relative permeability model were obtained by fitting profiles from one drainage (oil injection) and one imbibition (water/alcohol injection) displacement. The resulting parameters were used to construct the analytical solutions for the remaining displacements. Development of the analytical solutions to Riemann problems is outlined.
Different parameters are obtained for the imbibition and drainage experiments, indicating that hysteresis occurs in the experiments. Comparison of the experimental results with the analytical solutions shows that the mathematical model captures the essential features of the experimental displacements. In the cases in which the analytical solutions fail to model accurately the physical displacements, the effect of simplifying assumptions in the model are examined.
Guo, Xiao (Southwest Petroleum Inst.) | Du, Zhimin (Southwest Petroleum Inst.) | Sun, Lei (Southwest Petroleum Inst.) | Huang, Wanxia (PetroChina Jinlin Oilfield Company) | Zhang, Cai (PetroChina Southwest Oil & Gasfield Company)
Most of the low permeability oil reservoirs in Jilin oil field of China have reached their economic limit of production by waterflooding and even many wells have been abandoned due to low productivity. Interest in recovery enhanced technology of tertiary miscible or immiscible CO2 flooding is increasing in these low permeable reservoirs. In this paper, a laboratory study using a high-pressure PVT cell and a simulation study using full-field fully equation-of-state (EOS) compositional reservoir modeling were undertaken to optimize the design of a miscible or immiscible CO2 flood pilot project for the Xinli Unit in Jilin oil field. The laboratory study includes phase behavior analysis, asphaltene deposition assessment, and minimum miscibility pressure (MMP) determination in the CO2 corefloods. Based on building a full-field 3D geologic model and history matching waterflood performance, a preliminary CO2 flood reservoir modeling has been used to distinguish displacement mechanisms and reservoir performance of natural depletion, continued waterflooding, continuous CO2 and water-alternate-CO2. The simulation study and the pilot test showed water-alternate-CO2 after waterflooding is an effective method of improved oil recovery for the low permeability reservoir and it can appreciably reduce water production and enhance oil recovery. Simulation studies has also been completed to determine an optimal water-CO2 ratio, optimal CO2 slugs and optimal CO2 injection rate. The pilot operation is now well implementing according to above-mentioned study achievements. Future plans for water-alternate-CO2 optimization include continuation of performance monitoring to help optimize tapering strategy in order to enhance further oil recovery in the low permeability oil reservoir.
A considerable portion of the world's hydrocarbon endowment, and even more so if resources from the Middle East are excluded, are in carbonate reservoirs. Carbonate reservoirs usually exhibit low porosity and may be fractured. These two characteristics in addition to oil-to-mixed wet rock properties usually results in low recovery. When enhanced oil recovery (EOR) strategies are pursued, the injected fluids will likely flow is through the fracture network, bypassing oil in the rock matrix. The high permeability in the fracture network and its low equivalent porous volume result in early breakthrough of the injected fluids. Infill drilling programs and well conformance strategies, mostly gas and water shutoff, have been effectively used to mitigate the early breakthrough and increase oil recovery. However, in most cases, 40 to 50% of the original oil in place (OOIP) is not produced.
A large number of EOR field projects in carbonate reservoirs have been reported in the literature since the early 70's. The field projects showed the technological capability to increase oil recovery and estimated long run costs for their operation. This increase in oil recovery would directly result in additional reserves extending the productive life of the different assets. However, the technical results were not matched by their economic viability given the price environment of the time. In some cases high upfront investments created insurmountable barriers for the technology's application despite the promise of higher returns. In other cases, the high marginal costs eliminated all benefits from the increased recovery. The latter was especially true for EOR processes based on chemical and thermal methods. Over the last three decades, many improvements have reduced the cost per incremental barrel as will be seen below. Carbon dioxide flooding (continuous or alternating with water-WAG) is the dominant EOR process in the United States, mostly due to the availability of appropriate CO2. CO2 EOR is also the stepping stone towards sequestering carbon which could become a future business opportunity if carbon trading ever is implemented.
This paper presents an overview of EOR field experiences in carbonate reservoirs in the United States, an analysis of recent efforts and discusses briefly on new opportunities for novel chemical methods. The main EOR experiences reviewed are CO2 injection, polymer flooding, steam injection and in-situ combustion (air injection).
A large scale miscible water-alternating-gas (WAG) project was implemented in the Prudhoe Bay field in 1987. Many of the original patterns are no longer receiving miscible injectant (MI) due to pattern maturity and diminishing EOR response. The EOR project is being revived in the gravity-dominated eastern part of the Prudhoe Bay Field waterflood area, Flow Station 2 (FS2), by using horizontal sidetracks to place MI at various locations within existing conventional WAG patterns which have a significant remaining EOR target.
The sidetracks are completed at the toe and then perforated sequentially along the length of the horizontal wellbore to allow up to 7 independent points of miscible gas injection. Distributing the injection points enables MI to contact additional pore volume not contacted by the original WAG injector due to gravity segregation of the MI as it moves away from the injection wellbore.
Typical WAG benefits in this area range between 0.5 to 2 MMSTB. MIST injectors (MI Sidetracks) are recovering an additional 1.5 to 4.8 MMSTB in patterns that have already been WAG flooded. Typical MIST patterns accumulate 3 to 4 times the EOR reserves of conventional vertical well WAG patterns.
This paper will explain the reservoir characteristics that contribute to such large incremental recoveries. It will also cover well design and operational issues. Based upon the success of the initial MIST program, several additional MIST patterns have been drilled, and more are possible.
The Prudhoe Bay field is the largest oilfield in North America with total estimated ultimate recovery of roughly 13 billion barrels and a current production rate of approximately 400 MSTB/D. The field is overlain by a large gas cap, and the majority of the field is being produced by gravity drainage. Waterflood and miscible EOR operations at Prudhoe Bay are confined to the downstructure and peripheral areas of the field and produce about 120 MSTB/D. Waterflood patterns are typically inverted nine-spots with 80-acre well spacing (see Fig. 1).
Prudhoe Bay EOR began in late-1982 with an 11-pattern pilot project. The Prudhoe Bay Miscible Gas Project (PBMGP) was initiated in 1987, and now consists of about 185 total patterns. MI composition varies somewhat, with a typical composition of 20 % CO2, 35 % C1, 19 % C2, 23 % C3, and 3% C4. Almost half the patterns are suspended for either mechanical reasons or EOR process maturity.[1-2]
The Sadlerochit group is the major productive interval of the field. This interval includes a thick section composed of high permeability fluvial sands and interbedded shales. In the FS2 area, these shales create up to four completely isolated flow intervals.
The FS2 waterflood area is the focus of this paper. The entire FS2 area is under waterflood, and most of the FS2 patterns have undergone miscible WAG flood. Currently, the FS2 waterflood is producing at a 92% watercut. Individual patterns range from 85% to 98% watercut, reflecting a large variation in maturity between patterns.
Central FS2 has been on WAG injection since 1987. Miscible gas EOR provided nearly half of the oil being produced from FS2 in the late 1990s. The WAG process still plays a significant role in the FS2 area. FS2 has 47 current WAG patterns. A total of 28 of those patterns no longer receive MI due to pattern maturity or mechanical problems. The remaining 19 patterns are eligible to receive MI. However, only 10 of those patterns have large enough benefits to compete for the MI usage over the near term.
The centrifuge method for capillary pressure curve measurement involves increasing the centrifuge speed in steps and measuring the liquid expelled from a short core plug, at equilibrium, for each step. However, the traditional methods for deducing approximate solutions for the capillary pressure curve are based on the assumption that the capillary pressure is zero at the outflow end of the core. In addition, the traditional centrifuge methods for capillary pressure measurement are time consuming. A full capillary pressure curve requires approximately 10 different rotational speeds. We have observed for most sedimentary rocks that the experimental magnetic resonance free induction decay is single exponential and the effective transverse relaxation time (T2*) is largely insensitive to fluid saturation. These features ensure that Centric Scan SPRITE (single-point ramped imaging with T1 enhancement) is a quantitative magnetic resonance imaging (MRI) method, since its local image intensity is directly proportional to the local fluid content. We propose a single-shot method to measure the capillary pressure curve of a long rock core using a single-speed centrifuge experiment and one-dimensional Centric Scan SPRITE MRI to determine the fluid saturation distribution, S(r), along the length of the core. A full capillary pressure curve can be directly determined by the relation of S(r) and the capillary pressure distribution, Pc(r), along the length of the core.
The single-shot method, employing a desktop centrifuge and a desktop permanent magnet based one-dimensional MRI instrument, has been applied to measure the primary drainage, imbibition, and secondary drainage capillary pressure curves for reservoir rocks.
The proposed method for determining the capillary pressure curve is rapid, cheap, and precise. The capillary pressure curve can be obtained straightforwardly with about 40 data points. The duration of the experiment is approximately 10 times less than the traditional method. Since only a single moderate rotational speed is employed, the outflow boundary condition can be maintained, and the effect of gravity can be neglected. In addition, the long rock cores employed for the single-shot method result in a relatively small radial effect.
Capillary pressure results from the interaction between a wetting fluid, and a non-wetting fluid, as well as their bounding solid matrix. Capillary pressure critically influences the initial reservoir fluid distribution and dynamic processes of oil recovery. Capillary pressure is the most fundamental rock-fluid property in multi-phase flows, just as porosity and permeability are the most fundamental properties in single-phase flow in oil and gas reservoirs .
In evaluating hydrocarbon reservoirs, laboratory capillary pressure curve measurements on reservoir cores are directly applied to determine many basic petrophysical properties, for example: pore size distribution, irreducible water saturation, residual oil saturation, and wettability of reservoir rocks. In addition, they are used to determine the initial water and oil saturation as a function of height above the free water level, approximate oil recovery efficiency, and to calculate the relative permeability [2-4]. Capillary pressure can also have a significant impact on water flood performance .
In the laboratory, the capillary pressure curve can be determined with (1) mercury injection method, (2) porous diaphragm or membrane, and (3) centrifugal methods, based on hydrostatic equilibrium . The porous diaphragm method is a direct and accurate technique, but the measurement is extremely time-consuming, since the equilibration time can be weeks or months for each individual pressure point. The mercury injection method is rapid, but it is a destructive method. In addition, the mercury injection measurement does not provide information on reservoir wettability, and mercury is hazardous to human health and the environment.
We present a model of mixed-wet triangular tubes that calculates three-phase capillary pressure and relative permeability curves. Several ?uid con??gurations may occur in triangular pore cross-sections, and capillary displacements may either occur as piston-like displacements of the ?uids occupied in the bulk, or as piston-like displacements of the ?uids in layers. To our knowledge, this latter type of displacement has not been analyzed before in mixed-wet pores. Using minimization of Helmholtz free energy, we derive accurate three-phase capillary entry pressures for such layer displacements, accounting for contact-angle hysteresis. Numerical examples are presented to illustrate how the entry pressures for the different possible displacements relate to each other during gas and water invasion into pores with a speci??c ?uid con??guration. It turns out that the entry pressures for related displacements are consistent. This implies that pores occupied by the same ?uid in the bulk portion must have the same ?uid con??guration for a constant value of capillary pressure.
With this model we calculate three-phase capillary pressure and relative permeability, and explore how the saturation-dependencies of these quantities change according to saturation-reversal points. We simulate the sequence of processes primary drainage, imbibition and gas invasion, for different maximum capillary pressures P max/ow after primary drainage.
In the simulation results presented here, we ??nd that the oil and gas relative permeability, and their saturation-dependencies, are sensitive to variations of Pmax/ow, while the water relative permeability is less sensitive. Such effects are absent in cylindrical tubes. This is caused by the capillary entry pressures, which are strongly affected by hinging interfaces in the corners of angular pores when contact-angle hysteresis is assumed. Thus the choice of pore geometry is important if hysteretic capillary pressure and relative permeability relationships are simulated using network models. With respect to these ??ndings, relative permeability and capillary pressure correlations should be formulated with parameters that strongly depend on saturation-reversal points such that different saturation-dependencies can be accounted for in subsequent invasion processes.
Relative permeability and capillary pressure are required as functions of the saturations to solve the equations for three-phase ?ow in reservoir simulation. These relationships are normally formulated as simple correlations with adjustable parameters. In the reservoir, situations may occur where one of the phases appears or disappears, e.g., during phase transitions between gas and oil, or when a zero residual oil saturation is approached by drainage through continuous spreading layers in the crevices of the pore space. To implement these scenarios in a numerical reservoir simulator without creating convergence problems, the correlations must account for a smooth transition between two-and three-phase ?ow.
In the oil industry three-phase capillary pressure and relative permeability curves have traditionally been predicted from corresponding two-phase measurements. However, both experimental and numerical work have shown that this practice may not be valid. Moreover, micromodel studies of three-phase ?ow have revealed that the ?uid distribution and the displacement mechanisms at the pore scale may be more complex than for two phases.[1,2] These ??ndings emphasize the need for direct measurements of three-phase capillary pressure and relative permeability curves for various conditions. However, in three-phase ?ow there is an in??nite number of possible displacement paths because of two independent saturations. Hence, it is impractical to perform time-consuming measurements of a vast amount of different processes for several rock and ?uid properties. This points out the importance of developing physically-based pore-scale network models[3-6] to compute the relative permeability and capillary pressure curves. A pore-scale model, tuned to reproduce the measured data, may be employed to predict these quantities for displacement paths not covered by the measurements.