The continued use of gas injection to improve oil recovery and the prospects for its increased use throughout the world provide impetus to improve sweep efficiency of injected gas. Work is being carried out to improve understanding and the economics of mobility control agents. This paper describes the use of foam to decrease the mobility of gas in coreflooding apparatus at reservoir conditions. Foam behavior and adsorption, two of the mechanisms required to model surfactant requirements, are studied in this project. This study uses a commercial surfactant, nitrogen gas, and reservoir conditions of 10.34 MPa (1500 psi) and 40°C (104°F), and Indiana limestone. Variables are surfactant concentration, flow rate and foam quality.
At a constant gas flow rate, gas mobility slightly decreases with increasing foam quality when below the critical foam quality (fg*) and increases with increasing foam quality above fg*. Increased surfactant concentration leads to the decrease of gas mobility. Comparing coinjected surfactant and gas (CSG) with coinjected water and gas (CWG) shows that the mobility of CSG is an order of magnitude lower than that of CWG. Also, it took more time for CSG to reach steady state compared to CWG, even with a surfactant pad conditioning the core before surfactant and gas were coinjected.
A common scenario in many mature oilfields is to have most of the wells producing hydrocarbons with high water cuts. These wells are commonly not considered as good candidates for matrix stimulation. Water based treating fluids would enter preferentially into zones with high water saturations leaving oil zones untreated with a final result of increasing overall water production. However if the water production mechanism is understood and the appropriate fluids are selected then stimulating producer wells with high water cuts can be a rewarding operation. The treatment can be carried out while providing favorable economics to the entire operation.
The key fluid for treating high water cut wells is a Viscoelastic fluid that provides self-diversion from water to oil bearing formations. At the same time this same fluid can be used, on long intervals, to divert matrix stimulation treatments from stimulated to un-stimulated intervals or from high permeability intervals to low permeability intervals. These features are unique and inherent to its nature and the particular break mechanism making them suitable for selective placement and uniform zone coverage even for bull heading operations.
The paper presents the experiences with this Viscoelastic fluid used in nine different mature producer wells with pre¬treatment water cuts ranging from 32% to 94%. One additional case in presented on a newly drilled producer that was perforated and completed very close to a water zone that was successfully stimulated without any increase in produced water cut. Treatments presented include both cases in which fluids are bull-headed and placed through coiled tubing. The case histories included in the paper illustrate the pre and post treatment production results obtained. All are characterized by the fluid usage contributing to the stimulation being uniformly conveyed across the oil-bearing portion of the reservoir and away from the watered out intervals.
A description of the well candidate selection process, formation damage identification and the remedial treatment design, execution and results is briefly discussed along with the economic impact that such treatments offer to mature oilfields.
Several mature fields are located offshore the coasts of Cameroon, Gabon and Congo in water depths ranging from 9 m to 95 m. These fields were discovered in the early 1960s and are still on production. The wells are draining mature reservoirs that require a relatively large amount of intervention work such as matrix acidizing, water control, scale removal and sand consolidation to maintain an economic production rate.
The reservoirs are made up by several stacked reservoir that initially had different pressures regimes but presently most of them have the same sub hydrostatic pressure. The reservoir gross heights range from 80 m to 500 m. The composition of the matrix is mainly sandstone however there can be a significant carbonate content that can reach 35%. In the southern portion of the area considered there are also limestone reservoirs, which are often interbedded with sandstone lenses.
As these reservoirs have been in production for several decades pressure maintenance is normally carried out with water injection. The produced oil has a low GOR hence there is no gas injection for pressure maintenance however the produced gas in used for lifting the oil through gas lift systems. The application of Electrical Submersible Pumps for artificial lift is growing in these fields as the technology that allows these pumps to handle sand production has evolved in the recent years.
In the early stages of the exploitation of these fields matrix acidizing was the most frequently carried out operation as it allowed to obtain significant hydrocarbon production increases at a relatively small economic expenditure. The damage encountered in these wells is either deposition of carbonate scales in the near wellbore region and perforation tunnels or migration of matrix fines, with scaling being the most common damage mechanism.
This paper discusses the results of the application of horizontal waterflooding technology to improve the recovery of oil from older fields. A multi-disciplinary approach combining geological interpretations, rock mechanics evaluations, reservoir simulation studies, and drilling technologies was employed. A range of reservoir conditions in which the technology is viable is discussed and the results of the field tests are presented.
The major focus has been on the shallow sandstone reservoirs in northeast Oklahoma and southeast Kansas. It has been demonstrated that additional oil can be recovered in several different reservoir environments in these older fields, by utilizing a combination of horizontal and vertical wells. Two previous SPE papers described the results of a Department of Energy (DOE) supported horizontal waterflooding pilot located in the Wolco Field, Osage County, Oklahoma.
The technology has continued to evolve over time. The key to assessing the potential for a horizontal well application is a thorough understanding of the reservoir description, including the oil saturation, depositional environment, reservoir pressure, permeability, and an evaluation of any prior production and/or injection. Other parameters include the length, spacing, positioning and orientation of the injectors and horizontal producers in the target zone. Use of rotary-steerable drilling equipment has made it possible to drill underbalanced, short-radius horizontal laterals at a low cost.
Special procedures have been adopted to permit the transport of openhole logging equipment through the short-radius curve to the end of the lateral, providing a good description of reservoir properties and detecting the presence and orientation of natural fractures.
Results from several successful horizontal well projects are discussed. These include (1) two horizontal waterfloods in shallow Bartlesville sandstone reservoirs, (2) recovery from a rim of moderately heavy oil underlain by water, and (3) an application of horizontal waterflooding in a moderately heavy oil reservoir.
The major objectives of this paper are to discuss the industry trends in the application of horizontal wells in flooding operations and to describe the specific experiences of Grand Directions, LLC (Grand), a division of Grand Resources, Inc. Grand has been developing and applying horizontal well technology during the past four years, with a focus on the Pennsylvanian sands in the mid-continent area. Significant advancements have been made in a variety of reservoir environments,[1-3]
Waterflooding has been successfully used for many years in the recovery of oil from petroleum reservoirs. Successful waterfloods often recover as much or more oil than in the primary recovery phase. In spite of the many successes, waterfloods have not always been effective from a technical and/or economic basis. Common problems have included reservoir heterogeneities that cause the channeling of water; low permeability which limits the rate at which water can be injected below the fracture-parting pressure into the reservoir, and high infrastructure costs for applications in reservoirs that are deeper or located offshore.
Yang, Fulin (U. of Wyoming) | Wang, Demin (Daqing Oil Company) | Wu, Wenxiang (Daqing Petroleum Institute) | Wu, Junzheng (Daqing Oilfield Co. Ltd.) | Liu, Weijie (Daqing Oilfield Co. Ltd.) | Kan, Chunling (No. 1 Oil Production Co. Daqing Oilfield Co. Ltd.) | Chen, Qinghai (Daqing Oilfield Co. Ltd.)
The results of lab tests show that an incremental recovery over water flooding of more than 20% OOIP (original oil in place) can be obtained by early time injection of high molecular weight, high concentration polymer solutions, and the earlier the better. The incremental recovery is comparable to surfactant flooding but at a lower cost.
After the success of a pilot test injecting high concentration polymer fluids in Daqing Oil Field, a high concentration (concentration 1,500 ppm ~ 2,000 ppm, viscosity 400 mPa.S ~ 500 mPa.S) polymer flood pilot test has been started in May 2003. The purpose is to (1) study the feasibility of high concentration polymer flooding, (2) provide technical and practical experiences for expanding this technique to other areas of Daqing Oil Field. The pilot is located in the West Central area of Daqing Oil Field and consists of 9 injectors and 16 producers. Before high concentration polymer flooding, 0.247 pore volumes of low concentration (1,000 ppm, viscosity 44mPa.S~51 mPa.S) polymer solution had been injected and the water cut at the central area had reached its lowest point (65.5%). By the end of Dec. 2005, the water cut at the central area was 79.1%. After injecting high concentration polymer solution, the rate of the water cut increase slowed down and then the water cut decreased from a maximum of 79.6% to a minimum of 73.1% (a decrease of 7.5%) again. The current daily oil production is 29.5 tons. The daily oil production increased from a minimum of 29.8 tons to a maximum of 40.5 tons (an increase of 35.9%). The current recovery over that of water flooding is already 14.3% OOIP. According to numerical simulation, when the water cut reaches 98%, 19.8%~22.9% OOIP incremental recovery over that of water flooding will be attained.
Recently, 6 dispersed wells located in the West Central area of Daqing Oil Field started to inject a higher concentration of polymer fluid also. The 6 wells were first stimulated and then increased the concentration of the injected polymer solution from 1,000ppm to 1,300ppm. At present, good results have been obtained.
The above results illustrate that the injection of high concentration polymer fluids in the field is feasible and can further enhanced the oil recovery significantly. Very few fields have injected such high concentrations of polymer fluids; it should be of reference value to the design and implementation of future chemical (especially polymer) floods.
Polymer flooding has been field tested for more than 30 years and Daqing Oil Field has industrial scale implemented it for 9 year  s. In recent years, many petroleum engineers [2-3] consider that polymer flooding can also improve microscopic oil displacement efficiency due to the visco-elastic properties of polymer solution. From results on artificial cores, Wang Demin, etc.  deemed that an incremental oil recovery over water flooding of more than 20% can be obtained by injecting high concentration polymer solution. After the success of a pilot test injecting high concentration polymer fluids in Daqing Oil Field , a high concentration polymer flood pilot test has been started in May 2003. The purpose is to (1) study the feasibility of high concentration polymer flooding, (2) provide technical and practical experiences for expanding this technique to other areas of Daqing Oil Field. The pilot is located in the West Central area of Daqing Oil Field and consists of 9 injectors and 16 producers. Recently, 6 dispersed wells located in the West Central area of Daqing Oil Field started to inject a higher concentration of polymer fluid also. The results illustrate that the injection of high concentration polymer fluids in the field is feasible and can further enhanced the oil recovery significantly. Very few fields have injected such high concentrations of polymer fluids; it should be of reference value to the design and implementation of future chemical (especially polymer) floods.
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.
Foam is used in the oil industry in a variety of applications, and polymer is sometimes added to increase foam's stability and effectiveness. A variety of surfactant and polymer combinations have been employed to generate polymer-enhanced foam (PEF), typically anionic surfactants and anionic polymers, to reduce their adsorption in reservoir rock. While addition of polymer to bulk foam is known to increase its viscosity and apparent stability, polymer addition to foams for use in porous media has not been as effective.
In this pore-level modeling study, we develop an apparent viscosity expression for PEF at fixed bubble size, with the intention of better interpreting the conflicting laboratory coreflood data available. To derive the apparent viscosity, the pressure-drop calculation of Hirasaki and Lawson (1985) for gas bubbles in a circular tube is extended to include the effects of shear-thinning polymer in water, employing the Bretherton's asymptotic matching technique. For polymer rheology, the Ellis model is employed, which predicts a limiting Newtonian viscosity at the low-shear limit and the well-known power-law relation at high shear rates. While the pressure drop due to foam can be characterized fully with only the capillary number for Newtonian liquid, the shear-thinning liquid requires one additional grouping of the Ellis-model parameters and bubble velocity.
The model predicts that the apparent viscosity for PEF shows behavior more shear-thinning than that for polymer-free foam, because the polymer solution being displaced by gas bubbles in pores tends to experience a high shear rate. Foam apparent viscosity scales with gas velocity (Ug) with an exponent [-a/(a+2)], where a, the Ellis-model exponent, is greater than 1 for shear-thinning fluids. With a Newtonian fluid, for which a =1, foam apparent viscosity is proportional to the (-1/3) power of Ug, as derived by Hirasaki and Lawson.
A simplified capillary-bundle model study shows that the thin-film flow around a moving foam bubble is generally in the high-shear, power-law regime. Since the flow of polymer solution in narrower, water-filled tubes is also governed by shear-thinning rheology, it affects foam mobility as revealed by plot of pressure gradient as a function of water and gas superficial velocities. The relation between the rheology of the liquid phase and of that of the foam is not simple, however. The apparent rheology of the foam depends on the rheology of the liquid, the trapping and mobilization of gas as a function of pressure gradient, and capillary pressure, which affects the apparent viscosity of the flowing gas even at fixed bubble size.
Addition of polymer has been proposed as a way to stabilize foam, especially in the presence of oil. This study probes the putative stabilizing effect of polymer on foam in terms of steady-state properties. Specifically, we tested the effect of polymer addition on the two steady-state foam regimes identified by Alvarez et al. (SPEJ, 2001).
For the two polymers (xanthan and partially hydrolyzed polyacrylamide), two oils (decane and 37.5º API crude oil), and an alpha-olefin sulfonate surfactant, it appears from coreflood pressure gradient that polymer destabilizes foam modestly, raising water saturation and water relative permeability. The increased viscosity of the aqueous phase with polymer counteracts the effects of destabilization of foam. For the same polymers and surfactant, polymer does not stabilize foam in the presence of decane or 37.5º API crude oil relative to foam without polymer. Surface-tension measurements with these polymers and surfactant likewise showed no evidence of presence of polymer at the air-water interface that might stabilize foam lamellae between bubbles. This suggests that, for similar polymers and surfactants, addition of polymer would not give stronger foam in field application or stabilize foam against the presence of crude oil.
Complex behavior, some of it in contradiction to the expected two steady-state foam regimes, was observed. At the limit of, or in the place of, the high-quality regime, there was sometimes an abrupt jump upwards in pressure gradient as though from hysteresis and a change of state. In the low-quality regime, pressure gradient was not independent of liquid superficial velocity, but decreased with increasing liquid superficial velocity, as previously reported and explained by Kim et al. (SPEJ, 2005).
This paper reviews design and performance data on sixteen (16) CO2 huff ‘n puff projects conducted in different wells in the Forest Reserve oilfield of Trinidad and Tobago over the last twenty (20) years. Specific inferences on conditions under which these projects succeeded in increasing oil production were generalized taking into account published results of similar projects elsewhere.
With a variety of technical, operational and economic variables, a strong correlation or a definitive conclusion is difficult. However, by correlating various performance attributes with different parameters, certain inferences are drawn and tested which could be used to:
a. Determine if a candidate well could benefit from CO2 huff ‘n puff operations and
b. Identify optimal design and operational configurations in specific situations, based on field experience and engineering considerations.
Successful projects were conducted in reservoirs with crude oil gravities from 11- 38ºAPI and in-situ viscosities from 0.5 to 3000 cp (mPa.s) porosities of 11 to 32%, depths from 1150 to 12870 feet (345 to 3900 m), thicknesses from 6 to 220 feet (2 to 67 m) and permeabilities ranging from 10 to 2500 mD. Huff ‘n puff operations benefited from high oil saturations, mild pressure support to production, soak intervals of 2 to 4 weeks and production against back-pressures to discourage excessive water or gas production. Successful operations had CO2 utilization ranging from 0.3 Mcf/barrel to 10 Mcf/barrel for light oil reservoirs and 5 Mcf/barrel to 22 Mcf/barrel for some heavy oil reservoirs.
CO2 huff ‘n puff operations are essentially near wellbore stimulation techniques which can lead to increased oil recovery via removal of some productivity damage, reduced oil viscosity, increased dissolved gas content, oil swelling and vaporization of lighter components of oil. They can also suppress water production. They have significantly boosted short-term oil production and generated quick payouts, especially at attractive oil prices. In certain cases, they have also provided strategic information on injectivity and pressure communication with adjacent wells, and helped determine if a drive process is indicated. This paper attempts to demonstrate that by properly understanding relevant reservoir mechanisms, one can screen specific prospects and design appropriate operations.
In miscible flooding, injection of solvent is often combined with water in an attempt to reduce the mobility contrast between injected and displaced fluids, and control the degree of fingering. Using traditional fractional flow theory, Stalkup estimated the optimum water-solvent ratio (or WAG ratio) when viscous fingering effects are ignored, by imposing that the solvent and water fronts travel at the same speed. Here we study how the displacement efficiency and the mobility ratio across the solvent front vary with the WAG ratio, when fingering is included in the analysis. We do so by computing analytical solutions to a one-dimensional model of two-phase, three-component, first-contact miscible flow that includes the macroscopic effects of viscous fingering. The macroscopic model, originally proposed by Blunt and Christie, employs an extension of the Koval fingering model to multiphase flows. The premise is that the only parameter of the model - the effective mobility ratio - must be calibrated dynamically until self-consistency is achieved between the input value and the mobility contrast across the solvent front. This model has been extensively validated by means of high-resolution simulations that capture the details of viscous fingering and carefully-designed laboratory experiments.
The results of this paper suggest that, while the prediction of the optimum WAG ratio does not change dramatically by incorporating the effects of viscous fingering, it is beneficial to inject more solvent than estimated by Stalkup's method. We show that, in this case, both the PVI for complete oil recovery and the degree of fingering are minimized.
Solvent flooding is a commonly used technology for enhanced oil recovery in hydrocarbon reservoirs, which aims at developing miscibility, thereby mobilizing the residual oil and enhancing the mobility of the hydrocarbon phase.[1,2] Despite its high local displacement efficiency, the overall effectiveness of solvent injection may be compromised by viscous fingering, channeling and gravity override, all of which contribute negatively to sweep efficiency.[3-7] In this paper we focus on the effect of viscous fingering, that is, the instability that occurs when a low viscosity fluid (solvent) is injected into a formation filled with more viscous fluids (water and oil).
Mobility control of the injected solvent can be achieved by simultaneous co-injection of water - typically in alternating water and solvent slugs (WAG). In this way, the mobility contrast between the injected and displaced fluids is reduced, thereby limiting the degree of fingering.
There is an optimum ratio of water and solvent that maximizes recovery - the sense of minimizing the number of pore volumes injected - while providing effective mobility control. For linear floods in homogeneous media, and without consideration of viscous fingering effects, a graphical construction of the optimum WAG ratio was given by Stalkup for both secondary floods (water-solvent injection into a medium filled with mobile oil and immobile water) and tertiary floods (water-solvent injection into a medium filled with mobile water and immobile oil). The design condition imposed in Stalkup's method is that the velocity of the water and solvent fronts be the same. Walsh and Lake performed an interesting analysis of the WAG ratio (the ratio of injected water to solvent) on the displacement efficiency for secondary and tertiary floods, using fractional flow theory. They did not include the effects of viscous fingering, but they estimated the mobility contrast across the solvent front as a measure of the severity of fingering.
The applications of foam are 3-D on a field scale. However, most previous research focuses only on properties of foam in 1-D. Experiments were performed in 3-D, and the compositional reservoir simulator UTCHEM was modified to predict foam flow in 3-D.
The 3-D experiments demonstrated that, under similar experimental conditions, the mobility of foam in a 3-D tank is greater than that in a 1-D column. They also showed that foam greatly increases lateral gas distribution along the bottom of the tank and the average gas saturation for both homogeneous and heterogeneous packings with the effects being significantly larger in the latter case. The reservoir simulator UTCHEM was modified for foam flow. The foam simulation parameters were measured in 1-D sand columns and the simulator was modified to match the 1-D and 3-D experiments. The proposed model successfully history matched the homogeneous and heterogeneous 3-D sand tank experimental results for average gas saturation, gas injection rate, gas distribution and pressure profile along the tank diagonal 6 inches from the bottom.
The results of this study represent an advance in understanding of foam flow in 3-D. The simulator could be used to design a foam process in 3-D.