Composite Acid Treatment for Mitigating Formation Damage in Gas Storage Reservoirs

The volume of gas in storage reservoirs may be computed from estimates of hydrocarbon pore volume and gas density. However, both are difficult to estimate accurately. Further, no adequate method has been presented for estimating reservoir performance during operation for volumetric gas-storage reservoirs. Normally, gas-storage reservoirs exhibit small pressure gradients in the area containing the storage wells, even under conditions of maximum injection or withdrawal. A zone of low permeability usually surrounds, and is in communication with, the permeable zone which causes the storage reservoir to exhibit a definite pressure lag, as evidenced by lack of pressure stabilization after extended periods of shut-in. An analysis is presented for determining pore volume and gas in place, and for predicting future reservoir behavior of such reservoirs. The mathematical development is presented and a solution is shown for an operating storage reservoir. Introduction Depleted gas reservoirs are often used for gas storage. The reservoir usually contains a permeable area in which numerous storage wells are located. The permeable zone permits high deliverability and injectivity with relatively small pressure loss. However, pressure equilibrium may not be attained even after long periods of shut-in because of the fact that the permeable zone is in communication with an adjacent tight section. Most of these gas-storage reservoirs are sand lenses, such as ancient beaches or offshore bars. The areal geometry of these reservoirs is normally such that flow in the tight zone will be approximately linear, and the solutions presented here should apply. Discussion For purposes of this paper, a gas-storage reservoir is considered to consist of a volume of permeable rock in communication with tight rock, all of which is surrounded by an impermeable barrier. Pressure gradients across the permeable zone are small due to low flow resistance and well density. Hence, the permeable zone is considered to be at a uniform pressure which is only a function of time as gas is injected or withdrawn. The tight zone is considered to be linear with uniform permeability and porosity, and the pressure in the tight zone is a function of both position and time. Two solutions for flow in this system are used to define the reservoir and determine its properties. The first solution is for an infinite linear tight zone in communication with the permeable zone. The expression for constant gas-withdrawal rate is ............................(1) where c is the constant. The expression is derived in the Appendix. The second solution is for a finite tight zone in communication with the permeable zone. An adequate solution may be adapted from Carslaw and Jaeger, as shown in the Appendix. ............................(2) L where b = and the 's are the roots of the DL expression L cot (L) + = 0.D Eqs. 1 and 2 are superposed to account for varying rates of production or injection and are used to fit gas-storage field reservoir history. The solution for the infinite case, Eq. 1, is first applied to field data for early times following a shut-in period. Constants BD and c are obtained by a least-squares fit of pressure and rate data. After the pressure wave from gas injection or withdrawal reaches the external boundary of the tight zone, the infinite solution will no longer apply and pressure behavior should be more nearly represented by Eq. 2 for a gas reservoir in communication with a finite linear tight zone. JPT P. 544^

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 18–22. Abstract In natural gas storage operations, seasonal pressure fluctuations in the gas reservoir cause the water from the surrounding aquifer to flow into and out of the gas sand. The theory of unsteady-state liquid flow through porous media developed by Van Everdingen and Hurst has been applied to predict the water movement into and out of the gas bubble for several postulated pressure cycles. Those cycles with as many pound-days above the original aquifer pressure as pound-days below, may cause the gas reservoir to slowly grow or shrink rather than hold to a constant volume. Applications to an actual field case study give the predicted gas reservoir monthly pressures and volumes as compared with the observed monthly pressures and volumes. Introduction A large number of natural gas storage reservoirs are bounded by or adjacent to large water-saturated formations called aquifers. The presence of these aquifers is usually evidenced by the production of water from wells delineating the gas-bearing sands. Some gas storage reservoirs in use today have been purposely developed on aquifers. Cyclic pressure variations in a gas storage reservoir cause water influx and efflux from the surrounding aquifer. This, in turn, results in a varying gas reservoir volume. The prediction of the effect of this aquifer fluid movement on the size and size variation of the gas reservoir can provide information valuable in the study of several reservoir engineering problems. The economics of gas storage operations are directly influenced by the influx of aquifer fluid into the reservoir since a shrinking storage reservoir requires increasing pressures for the storage of the same quantity of gas. Material balance and reserve or recovery calculations also obviously require knowledge of reservoir volume. Various other reservoir engineering calculations such as interpretation of well interference data, evaluation of physical characteristics of porous media, water coning, gas injection and pressure maintenance studies are typical problems where variations of volume due to edge or bottom-water encroachment becomes important.

Gas injection is the most widely applied recovery method in light, condensate, and volatile oil carbonate reservoirs. Gas has high displacement efficiency and usually results in a low residual oil saturation in the part of the reservoirs that is contacted with gas. The displacement efficiency increases when the injected gas is near-miscible or miscible with the oil. In addition to nitrogen and hydrocarbon gas projects, CO2-EOR has been the dominant gas EOR process. Gas-based EOR has been implemented in both mature and waterflooded carbonate reservoirs. In this paper, we present the results of a detailed experimental study aimed at understanding the performance and efficiency of gas injection in carbonate reservoirs. A series of immiscible and miscible gas injection coreflood experiments were performed using limestone reservoir cores under different injection strategies. To minimize laboratory artefacts, long cores were used in the experiments and to observe the effect of gravity both 2-inch diameter and 4-inch diameter (whole core) were used. The experiments were performed under reservoir conditions using live crude oil. The core wettability was restored by ageing the core in crude oil for several weeks under reservoir temperature. Hydrocarbon gas (methane) was used as the immiscible injectant and both CO2 and a mixture of 50% C1 and 50% CO2 were used as miscible injectant. All gas injection experiments were performed using vertically oriented cores and the gas was injected from the top unless it is stated otherwise. The main parameters investigated in this study are: 1- The effect of miscibility on oil recovery for both continuous gas injection and WAG, 2- The effect of gravity on gas sweep efficiency compared to water flooding, 3- the effect of gas-oil IFT on oil recovery when using the same oil, 4- the effect of oil type on oil recovery using the same injected gas at miscible and immiscible conditions, 5- the effect of immiscible gas injection on subsequent miscible gas injection performance and 6- Impact of CO2 cycle length on ultimate oil recovery. In addition, this work investigated the impact of the order of fluid injection where multiple WAG injection cycles were performed in separate experiments after water or gas injection. The main conclusions of this study are: 1- As expected miscibility has a significant impact on displacement efficiency and oil recovery where miscible gas recovered more than 20% extra oil compared to immiscible gas.2- A significant variation in oil recovery is observed for miscible gas injection, i.e., more than 10 saturation units difference, depending on the MMP between the injected gas and crude oil even when both experiments are performed at miscible conditions using the same injected gas. 3- The performance of tertiary CO2 flood was adversely affected by the slug of immiscible gas injected. Therefore, it is not recommended to have immiscible gas injection before miscible gas injection. 4- Regardless of injected gas type, gas injection with similar IFTs achieved similar oil recovery. 5- During WAG experiments, starting the injection cycles with water or gas did not have any impact on the ultimate oil recovery for both miscible or immiscible cases for one of the reservoirs while WAG_G (WAG starting with gas injection) recovered more oil for another reservoir. 6- Gravity has significant impact on oil recovery for both miscible or immiscible gas injection. Significant difference is observed in oil recovery when comparing CO2 injection on 2-inch and 4-inch diameter core sample or when comparing horizontal vs vertical immiscible gas injection and WAG experiment. 7- The longer the CO2 slug size the higher the oil recovery observed in gas injection experiments. The results of this study provide a rich and rarely available set of experimental data that can help improve and optimize gas and WAG injection in oil-wet carbonates.

Summary Gas injection is the most widely applied recovery method in light, condensate, and volatile oil carbonate reservoirs. Gas has high displacement efficiency and usually results in a low residual oil saturation in the part of the reservoir that is contacted with gas. The displacement efficiency increases when the injected gas is near-miscible or miscible with the oil. In addition to nitrogen and hydrocarbon gas projects, carbon dioxide (CO2) enhanced oil recovery (EOR) has been the dominant gas EOR process. Gas-based EOR has been implemented in both mature and waterflooded carbonate reservoirs. In this paper, we present the results of a detailed experimental study aimed at understanding the performance and efficiency of gas injection in carbonate reservoirs. A series of immiscible and miscible gas injection coreflood experiments were performed using limestone reservoir cores under different injection strategies. To minimize laboratory artifacts, long cores were used in the experiments, and to observe the effect of gravity, both 2 in. diameter and 4 in. diameter (whole core) were used. The experiments were performed under reservoir conditions using live crude oil. The core wettability was restored by aging the core in crude oil for several weeks under reservoir temperature. Hydrocarbon gas (methane) was used as the immiscible injectant, and both CO2 and a mixture of 50% C1 and 50% CO2 were used as miscible injectant. All gas injection experiments were performed using vertically oriented cores, and the gas was injected from the top unless it is stated otherwise. The main parameters investigated in this study are as follows: The effect of miscibility on oil recovery for both continuous gas injection and water alternating gas (WAG). The effect of gravity on gas sweep efficiency compared to waterflooding. The effect of gas-oil interfacial tension (IFT) on oil recovery when using the same oil. The effect of oil type on oil recovery using the same injected gas at miscible and immiscible conditions. The effect of immiscible gas injection on subsequent miscible gas injection performance. Impact of CO2 cycle length on ultimate oil recovery. The impact of the order of fluid injection where multiple WAG injection cycles were performed in separate experiments after water or gas injection. The main conclusions of this study are as follows: As expected, miscibility has a significant impact on displacement efficiency and oil recovery where miscible gas recovered more than 20% extra oil compared to immiscible gas. A significant variation in oil recovery is observed for miscible gas injection (i.e., more than 10 saturation units difference) depending on the minimum miscibility pressure (MMP) between the injected gas and crude oil, even when both experiments are performed at miscible conditions using the same injected gas. The performance of tertiary CO2 flood was adversely affected by the slug of immiscible gas injected. Therefore, it is not recommended to have immiscible gas injection before miscible gas injection. Regardless of injected gas type, gas injection with similar IFTs achieved similar oil recovery. During WAG experiments, starting the injection cycles with water or gas did not have any impact on the ultimate oil recovery for both miscible and immiscible cases for one of the reservoirs, while WAG_G (WAG starting with gas injection) recovered more oil for another reservoir. Gravity has a significant impact on oil recovery for both miscible and immiscible gas injections. A significant difference is observed in oil recovery when comparing CO2 injection on 2-in.- and 4-in.-diameter core samples or when comparing horizontal vs. vertical immiscible gas injection and WAG experiment. The longer the CO2 slug size, the higher the oil recovery observed in gas injection experiments. The results of this study provide a rich and rarely available set of experimental data that can help improve and optimize gas and WAG injection in oil-wet carbonates.

Previous studies have shown that foam, because of its unique structure, reduces gas flow in porous media. This blocking action of foam appears to be especially suitable for sealing leaks in underground gas storage reservoirs. Such reservoirs often have permeable areas in the overlying caprock that allow permeable areas in the overlying caprock that allow vertical migration of gas from the storage zone to the upper formations. The escaped gas represents both a safety hazard and an economic loss. Our objectives in this study were to evaluate the effectiveness of foam in preventing the escape of gas from a leaky gas storage reservoir and to find the foaming agents that were most suitable for this purpose. We simulated the behavior of a leaky gas reservoir with a sandstone model and found that foam was 99-percent effective in reducing leakage of gas through the model. The amount of foaming agent required to seal a leak depends on the adsorption-desorption properties of the agent. After testing many foaming agents, we concluded that best results are obtained with certain modified anionic esters of relatively low molecular weight. Less than 0.3 lb of such agents is required per barrel of pore space in Berea sandstone. This study indicates that foam generation should be an effective and economical method for reducing or stopping gas leakage from an underground storage reservoir. Introduction The practicality of underground gas storage is greatly dependent upon the confinement that the caprock provides for the formation to be used as a storage reservoir. In spite of numerous precautions, several gas storage projects are plagued by vertical migration of gas from the intended storage zone to upper formations. Such gas leaks pose a safety hazard and represent an economic loss. If leakage is very high, the storage operation may be uneconomical. In at least one cases the leak problem is minimized by periodically collecting the escaped gas from the upper formation and reinjecting it into the storage reservoir. While such a solution is feasible, it is economically unattractive because the leak limits pressures and gas injection rates. Furthermore, energy must be expended in order to circulate the escaped gas. Recent studies have shown that foam, because of its unique structure, reduces gas flow in porous media. This blocking action of foam appears to be uniquely suitable for sealing leaks in underground gas storage reservoirs. Our objectives in this study were to determine the effectiveness of foam in reducing gas flow in a model of a "leaky" gas storage reservoir and to find foaming agents most suitable for this purpose.

This article deals with comparative technical and economic aspects of conventional and some nonconventional methods of storing gas. Conventional gas storage was first begun by injection and subsequent production of gas in a depleted gas field in Ontario, Canada in 1915. Conventional methods also include storage in depleted in oil fields and aquifers. Aquifer storage was first introduced into the United States with the injection of gas into the Galesville aquifer at Herscher, Ill. in 1953. Nonconventional methods include storage of gas in coal mines, mined salt caverns steel pipe and earth strata with artificial caprock and lateral confinement created by impermeable chemical grouts. Another method is storage of liquified gas in frozen earth or mined caverns. The growth and status of gas storage in the U.S. and Western Europe is summarized and technical and economic factors are related to the probable future direction and growth of storage in these areas. Introduction Major markets for natural gas in the U. S. and Western Europe often consume more gas during the four coldest winter months than during the remainder of the year. Peak winter demand usually exceeds three times the average summer consumption rate. Unless some form of near-market gas storage is used, large enough pipelines must be installed from producing fields to handle this peak winter demand. The resulting pipeline load factor, defined as average yearly flow rate divided by maximum or design rate, is then low and gas transmission costs are high. Near-market storage of gas serves as a buffer to allow a high pipeline load factor. Experience shows that the savings in transmissions costs are generally two to three times the cost of storage. Technical Aspects of Underground Gas Storage In addition to the basic requirements of size and proximity to market, a gas storage reservoir must possess an impervious roof and lateral confinement. Depleted reservoirs offer a caprock of guarantied integrity and sufficient structural closure or other lateral confinement to contain the gas. Partly for these reasons, we prefer to store gas whenever possible in depleted fields rather than in aquifers. Abandoned or poorly cemented wells are sources of gas leakage in depleted fields. In many cases, considerable time and expense are necessary to locate and recondition or plug such wells. In general, however, this is cheaper than the initial drilling and completion of wells in developing aquifer storage. In developing aquifer storage, extensive geological and hydrological work is performed to investigate the adequacy of caprock integrity and structural or lateral confinement. In spite of this effort, many of the aquifer storage reservoirs in the U. S. leak gas to shallower formations. Extensive efforts failed to locate a source of the leak at the Galesville aquifer project in Herscher, Ill., and in 1960 over 13 MMcf/D were circulated from shallower formations back into the Galesville aquifer.' This amounted to 4.6 Bcf/year,* a significant fraction of the 34.2 Bcf stored at the end of that year. Delivery capacity is one of the most important considerations in designing a storage reservoir. For a given number of wells, the delivery rate is proportional to reservoir pressure which, in turn, is proportional to gas in place. This presents a problem since the largest required delivery rates often occur in the latter part of the winter when gas reserves are lowest. In the case of a dry gas reservoir this problem can be solved rather simply since the known, constant reservoir pore volume allows easy prediction of pressure from a given gas withdrawal schedule. From the predicted pressure behavior during the season, delivery capacity can be calculated for a given number of wells or the number of wells necessary to ensure a given delivery capacity. Water movement in aquifer and water drive fields considerably complicates the calculation of pressure as a function of gas withdrawn over the winter season. In this case, reservoir pore volume can vary considerably, growing with spring and summer injections and shrinking with winter withdrawals. Methods of calculating this water movement and relating it to reservoir pressure and withdrawals have been extensively studied and are described in the literature.

The construction of natural gas storage reservoir can effectively guarantee the seasonal peak demand of natural gas, but at present, the research on the construction of gas storage reservoir and the prediction of production and leakage risk is not comprehensive. Therefore, through the analysis and study of typical completion string, production mode and leakage risk of gas storage, the characteristics of different types of gas storage reservoirs are obtained. Among them, salt cavern gas storage reservoir mainly uses water-soluble cavity technology to store natural gas in salt cavern formed after the underground brine is extracted. The cavitations stage is completed by the auxiliary construction of water injection string+brine discharge center pipe. After the discharge of halogen, the central pipe is lifted out through non-kill well equipment and then the gas injection underground storage is carried out. This type of gas storage reservoir has the characteristics of high gas discharge rate, low base gas quantity, strong corrosion resistance of pipe column but high leakage risk. Compared with the salt cavern storage, the production string of the gas reservoir is mainly composed of packer, underground safety valve and gas seal tubing, and the production well seat sealing under the waste oil reservoir is used for gas injection and extraction. In addition, this paper also establishes a gas leakage annular zone pressure mathematical model based on one-dimensional gas migration equation, which can effectively predict the permeability of leakage points through well pressure test values and calculated values, and effectively evaluate the leakage risk of gas storage.

Hydrocarbon gas has been injected into the Ekofisk field for almost twenty years. Gas injection has always been for operational reasons. This case history reviews the historical performance and benefits of the gas injection. Gas migration, gas distribution and mechanisms involved when gas is injected into a naturally fractured chalk reservoir are discussed. The findings are based on field and laboratory data. The benefits are estimated by means of reservoir modelling. The Ekofisk field is a naturally fractured chalk reservoir with low matrix permeability. The natural fracturing enhances overall permeability and has made commercial production possible. Since gas injection commenced in 1975, a total of 1.2 TSCF of gas has been injected. All the gas has been injected into the crest of the field. This paper demonstrates that the natural fracture system at Ekofisk represents a medium for the injected gas to contact and mix with the reservoir fluids and that major fault systems are important factors for gas migration and gas distribution. There is no clear oil production response to gas injection. The production response that can be observed is generally limited to elevated GOR. Gas injection still appears to have benefitted oil recovery. Reservoir modelling suggests that gas injection will increase oil recovery by 2 to 3 percent of original oil in place. Historical benefits are, in addition to pressure support, swelling of the oil and vaporization/stripping of lighter hydrocarbons.

In accordance with Banyu Urip reservoir simulation for production outlook, produced gas is increasing over time causing the facility to become gas-constrained. With approximately 80% of the gas is being re-injected back for reservoir pressure maintenance, the existing Gas Injection (GI) capacity is limited by the backpressure which is close to the compressor pressure limit. Well conversion helps to resolve these challenges, subsequently allowing more gas production which translates to higher oil production. Repurposing the existing shut-in oil producers into gas injection wells require surface piping modification. The development of this project needs Surface and Subsurface team collaboration to acquire both hydraulic benefit and meet reservoir pressure maintenance requirement. It mainly consists of: Well selection criteria for shut-in oil producers Surface piping system modification concept and hydraulic calculation Gas injection wells operation and injectivity performance observation Address challenges from the converted wells (sulfur deposition, schmoo formation, injectivity loss) Subsurface selection criteria for conversion well candidate include ensuring all perforation intervals are already within gas zone by performing contact logging to evaluate the latest gas-oil contact. Selecting the appropriate gas supply route proved to be beneficial for gas injection wells operation and performance, as well as for the oil production. Injectivity data suggests that supplying gas injection from the gas lift manifold resulted in lower backpressure by 900 kPag, compared to flowing gas from gas injection manifold. Furthermore, two additional Gas Injection (GI) wells resulted in the significant reduction of compressor discharge pressure, allowing more gas to be re-injected back to the reservoir. It also provides more flexibility to perform one GI well preventive maintenance without continuous flaring. The project has successfully increased the gas injection capacity by approximately 30%, thus allowing higher produced gas to be handled by the system. It translates to additional oil production of 4,000 – 6,000 bbls/day while maintaining lower emission. This paper provides insight of successful effort in converting oil producer wells into gas injection wells with a proper measure and precautions for a gas-constrained facility. Simple modification of well conversion proved to be giving higher injection capacity and significantly impact the oil production.

This paper presents an evaluation on the combined use of horizontal wells and gas injection in a tight reservoir. The application of geo-statistics and compositional reservoir simulation are demonstrated in the evaluation to model heterogeneity and understand fluid behaviour. Normally, gas injection performance in a low-relief reservoir is poor due to adverse gravity segregation. Furthermore, gas injection performance tends to worsen if permeability improves toward the top of the reservoir. The combined use of horizontal wells and gas injection under various configurations was evaluated to optimise oil recovery in the tight part of a major reservoir in a giant oil field offshore Abu Dhabi. This part of the reservoir is characterised by very low permeability (<5 millidarcy average) with the best permeability in the upper portion. The evaluation concludes that the use of horizontal wells in a line drive pattern together with gas injection should greatly improve oil recovery in this tight reservoir. The improvement is attributed to the combined effect of linear flow and a large pressure gradient between the injector and producer due to the low permeability, drastically reducing the effect of gas over-ride due to gravity. Hence, as permeability increases, gas injection is predicted to be less effective. The results from the evaluation were used to optimise a pilot gas injection project. The effect of permeability heterogeneity at the scale modelled is not likely to be detrimental to gas injection. This is because the reservoir is predominantly of low permeability, even though, statistically, high permeability does exist. The geo-statistical modelling suggests that the likelihood of high permeability continuity is low and therefore is not likely to channel gas to producers. More important in the predicted performance of the geostatistical models is the method of up-scaling and permeability averaging. Misleading conclusions may result if the averaging process does not correctly account for the predominant flow regime.

This work presents the concept, progression, execution and results for a successful field implementation for a new technique to create insitu blocking foams in a gas condensate naturally fractured reservoir by the injection of the foaming agent dispersed in the hydrocarbon gas stream. This new technique aims at simplifying the operation and reducing the footprint and costs for the deployment of EOR foams in gas injection based projects. It also helps to overcome the disadvantage of limited reservoir volume of influence obtained by the SAG technique. The selected field area for the pilot was confirmed to be naturally fractured dominated both by the production and gas injection performance. The field area had only one oil producer and one gas injector, so monitoring the results of the pilot was simplified. The operation was carefully planned so that a ramp up in foamer solution concentration could be implemented at the field, and the response of the gas injector well could be monitored in real time. Additionally, a gas tracer program was implemented to track the fly times of the gas prior and after the dispersed foam treatment. About 1000 Bbls of foaming solution were dispersed in the hydrocarbon gas stream in one gas injector of a gas condensate Piedemonte field, whose injectivity performance was confirmed to be highly influenced by the natural fractures. Base gas injection conditions were about 30 MM scfd at 3800 psi WHIP. Once the dispersed foamer injection started, the gas injectivity in the well was progressively reduced to the point of increasing the WHIP to ~5000 psi, and the final gas rate was half of the base. The oil production well influenced by this injector changed its performance showing an increasing ramp in oil production and a reduction of the gas oil ratio (GOR) after the dispersed chemical injection period. The tracking of the gas tracers evidenced a delay in the gas fly times between the injector and the producer wells of two fold (63 days Vs 28 days), as a consequence of the dispersed foam treatment. This is the first time a successful foam EOR field pilot is done in a naturally fractured reservoir by the injection of the foaming agent dispersed in a hydrocarbon gas stream. It is believed this new foams technique could also be extended to other non-condensable gases at field operating conditions like CO2, Nitrogen, Air, and Flue Gas.

A Water-alternating-gas (WAG) injection is a broadly practised technique in oil fields. Gas viscosity is a significant parameter that can affect the efficiency of gas and WAG injections. By conducting the current coreflood experiments at reservoir conditions, we aimed to investigate the effect of gas viscosity on gas and WAG injection performance in terms of oil recovery and differential pressure. Both WAG injection experiments were performed on the same Clashach sandstone core, under weakly water-wet and near miscible (gas/oil IFT = 0.04 mN.m-1) conditions, using two different hydrocarbon systems (C1-nC4 and C1-nC10). To eliminate the impact of the experimental artifact, a long and large core (2ft x 2 in) was employed. In addition, after each initial water injection, water was pumped through the core at multi-rates, for further investigation of the impact of capillary end effects on our experimental results. To facilitate the interpretation of the data and the comparison, the same injection strategy and methodology were followed in both coreflood experiments. In each injection scenario, four water slugs, starting with primary water flooding, were injected in an alternating manner with four gas cycles. The results of these WAG experiments showed that the cyclic oil recovery performance during different water and gas injection cycles increased as the number of WAG slugs increased. Investigating the effect of gas viscosity on the performance of oil recovery during gas and WAG injections revealed higher oil recovery performance during the tertiary (three-phase displacement) water injection cycles that were subsequent to the preliminary water flood periods, in WAG injection with C1-nC4 than that in C1-nC10. In contrast, the efficiency of oil recovery during the successive gas injection cycles (under three-phase conditions) was lower in C1-nC4 than that in C1-nC10. The ultimate oil recovery achieved by WAG injection under weakly water-wet and near miscible conditions reached 93 % and 94.5 % (IOIP %) in C1-nC4 and C1-nC10 respectively. On the other hand, the results showed also an extra oil quantity of 3.7 % (Sor%) recovered during the alternation of water and gas injections post-waterflood, by C1-nC10 compared with that in C1-nC4. Studying the impact of the gas viscosity on the injectivity showed a significant drop in the periodic gas injectivity, during different gas injection cycles in WAG injection for C1-nC10 compared with its values for C1-nC4. A comprehensive series of data sets, generated for two WAG injection experiments with different hydrocarbon fluids (C1-nC4 and C1-nC10) will be reported in this paper. WAG injection is a special case that involves complex multi-phase and multi-physics processes, which are well-known to be difficult to reliably predict by the current existing reservoir simulators. Therefore, representative and reliable experimental data are needed to improve our understanding of the complex underlying mechanisms of oil recovery by WAG injection and to develop improved models and methodologies for reliable predictions of the performance of WAG injection under reservoir conditions.

Long core flow experiment was conducted to study problems like excessive injection pressure and effective lag of oil wells during the polymer flooding in Honggang reservoir in Jilin oilfield. According to the changes in viscosity and hydrodynamic dimensions before and after polymer solution was injected into porous media, the compatibility of polymer hydrodynamic dimension and the pore throat size was studied in this experiment. On the basis of the median of radiusRof pore throats in rocks with different permeability, dynamic light scattering method (DLS) was adopted to measure the hydrodynamic size Rh of polymer solution with different molecular weights. The results state that three kinds of 1500 mg/L concentration polymer solution with 2000 × 104, 1500 × 104, and 1000 × 104molecular weight matched well with the pore throat in rocks with permeability of 300 mD, 180 mD, and 75 mD in sequence. In this case, the ratios of core pore throat radius median to the size of polymer molecular clewR/Rhare 6.16, 5.74, and 6.04. For Honggang oil reservoir in Jilin, when that ratio ranges from 5.5 to 6.0, the compatibility of polymer and the pore structure will be relatively better.

Gas storage reservoirs are utilized in many locations to seasonally store gas in summer months for periods of high demand in the winter. This generally involves the cyclic pressurization and depressurization of the reservoir on an annual basis. If the storage reservoir overlies an aquifer or residual oil leg, this may involve the cyclic motion of the gas-liquid contact and gas zone. This paper documents an extensive series of reservoir condition relative permeability experiments conducted on core material from a gas storage reservoir in southern Ontario to investigate the effects of cyclical pressurization and depressurization on reservoir performance. The tests illustrate how the cycling of applied net overburden pressure and the presence of trapped gas and water saturations in the dynamic gas-liquid transition zone can affect the production and injection of gas in the storage reservoir. Applications of the data, and extensions to field performance are also presented. Introduction For many years, natural underground geologic traps have been utilized for storing gas and liquid hydrocarbons; these reservoirs are usually developed from known hydrocarbon reservoirs which have since been abandoned. The primary application of storage reservoirs is in the accumulation and storage of natural gas during periods of low demand in the summer months so that a large localized source of gas is readily available for periods of increased demand in the winter. For this reason, the reservoir is subjected to annual cyclic pressurization and depressurization as the gas is stored and removed from the reservoir. When an active aquifer or residual oil leg is present in the reservoir, these cyclic pressure fluctuations can result in an annual transgression and regression of the gas liquid contact. Encroachment of the liquid phase into the previously uninvaded portion of the reservoir is of interest to the operators of these fields because the residual saturation of the encroached fluid can have a profound effect on the deliverability and general performance of the contacted pore space. Experimentation and investigation of this phenomenon is possible through imbibition and drainage simulations to quantify the effects caused by two phase relative permeability relationships. An additional phenomenon associated with reservoir pressure cycling is that of rock compressibility effects. The gross overburden of the field remains constant as the internal pore pressure of the system oscillates. This yields a variation in the magnitude of the rock compressibility while the net overburden pressure changes as a function of pore pressure. The complexity of this scenario is further complicated by the compression and expansion of the trapped gas phase in the liquid filled pores. Hycal Energy Research Laboratories Ltd., in conjunction with Union Gas Limited, applied recent advancements in reservoir condition relative permeability techniques to conduct an extensive series of experiments to investigate the effects of these phenomena in the gas storage environment. Applications of the experimental data to field scenarios is also discussed.

The subject reservoir is a heterogeneous carbonate formation in a giant field located offshore Abu Dhabi. Five gas injection pilots were initiated in late 2001 in the Eastern, Central and Western parts of the field both as secondary and tertiary recovery methods to evaluate the benefit of gas injection for pressure support and for recovery improvement. With less than 10% of HCPV gas injection, the pilots to date have provided valuable insight on production performance and pressure support, gravity override, swelling effect and flow assurance issues (such as asphaltene deposition) in the field. Using a 3D compositional model, a sector modeling study was carried out for comprehensive evaluation of the pilot performance to date and to predict definitive results within reasonable time frame (3-5 years) which will have ramifications on long-term full field development decisions. Additionally, the objectives of simulation efforts were to evaluate different recovery processes (gas/water/WAG) and assess key reservoir uncertainty (volumetric sweep) due to reservoir heterogeneity (high permeability streaks). Initially, the sector model was history matched with nine years of pilot performance while both reservoir heterogeneity and well spacing sensitivities were tested in the model. The history matched sector model was utilized to predict performance under different operating conditions using both gas, water and water alternating gas (WAG) injection methods. This paper describes the pilot performance, field observations and results of a sector model study including history match, sensitivity and predictions under different injection scenarios on two of the pilots. Based on the performance and surveillance data gathered on the two pilots and sector modeling study, it was established that both pilots have met their objectives and can be concluded. Through the integration of field observations and sector modeling work, the study provided valuable insight on optimum recovery processes, well spacing and well completion requirements for long-term field development.