Dry Gas Injection Research Articles

The Effect of Gas Injection on the Enhancement of Condensate Recovery in Gas Condensate Reservoirs: A Comparison Between a Synthetic Model and PVT Cell Results

Gas condensate reservoirs have complicated fluid flow and thermodynamic processes. As reservoir pressure decreased, the gas condensate system exhibits a dew point. As pressure is reduced, liquid condenses from the gas to form free liquid in the reservoir. This liquid phase develops with pressure reduction and the composition of gas phase is changing due to pressure reduction. The condensate is deposited at such low liquid saturation that is usually trapped by surface tension forces, is therefore immobile, and cannot be produced. Condensate liquid builds up near wellbore causing a reduction in gas permeability and gas productivity. In order to prevent the condensate formation in reservoir, different scenarios have been proposed in which the most important method is gas injection to maintain the pressure or to revaporize the condensed liquid. In other words, the injection of dry gas into a retrograde gas condensate reservoir helps in vaporizing the condensate and increases its dew point. This study prepared a comparison between gas injection scenarios in cells (PVT studies) and a synthetic model of the reservoir. The main goal of this work is to investigate the lean gas recycling into the PVT cell and the synthetic model to enhance condensate recovery. In this work, these subjects were studied: the effect of CO2, separator gas, and N2 on condensate recovery enhancement and comparison of these scenarios with CO2, separator gas, and N2 injection and discussion on why the results are different in these two approaches. This study shows that when CO2, separator gas, and N2 are injected in PVT cell, deduction of condensed liquid during the pressure reduction of simulated constant volume depletion test at different injection volumes related to CO2 is more than separator gas and separator gas scenario is more than N2. In other words CO2 is the most effective and N2 is the least effective scenarios in reduction of condensate in the simulated constant volume depletion. But in the synthetic model, the results are completely different with the simulated PVT cell. In the synthetic model, deduction of condensed liquid during the different injection volumes related to N2 is more than separator gas and separator gas scenario is more than CO2. In other words N2 is the most effective and CO2 is the least effective scenarios in reduction of condensate in the synthetic model. Based on the type of condensate deduction mechanism, the three mentioned gases presented different results. N2 acts as the best gas when the decrease of liquid dropout is aimed to evaporate existing since at the same injection rate for all injected gases, N2 has increased the reservoir pressure more than the other gases and this reservoir pressure increase causes more re-vaporization at the synthetic model. In fact, the injection gas affects the decrease of liquid dropout formation indirectly. But if the injection gas affects directly on the reservoir fluid, CO2 acts as the best injection gas regarding the reservoir composition change. In this mechanism, the injection gas affects the liquid dropout formation directly.

Well injectivity during CO2 storage operations in deep saline aquifers—Part 1: Experimental investigation of drying effects, salt precipitation and capillary forces

Carbon Capture and Storage (CCS) is a technique than can potentially limit the accumulation of greenhouse gases in the atmosphere. Well injectivity issues are of importance for CCS because the gas injection rate must be maintained at a high level (a million tonnes of CO2 per year and per site) during the industrial operation period (30–40 years). The risk of altered permeability must therefore be determined in order to guarantee the sustainability and the security of the CO2 geological storage. Injection of dry gas in deep saline aquifers might lead to near wellbore drying and salt precipitation. The solid salt might then reduce the rock permeability by clogging pores or by pore throat restriction. The objective of this paper is to present new experimental results on the drying of rocks induced by continuous injection of large amount of dry gas (N2). The main goal of the study was to understand and model the physical processes that govern the decrease in water saturation in reservoir rocks.Two types of sandstone were used to study slow and fast drying rates and capillary effects on drying. The experimental results evince the main physical parameters that control the key mechanisms. In a companion paper in this issue (André et al., 2013), we show that the continuous approach in the context of a compositional two-phase flow model can fairly well predict the saturation evolution in the near wellbore and the alteration in permeability due to salt precipitation.

Effects of Porous Medium Heterogeneity on Vadose Zone Desiccation: Intermediate‐Scale Laboratory Experiments and Simulations

Soil desiccation (drying), involving water evaporation induced by dry gas injection, is a potentially robust vadose zone remediation process to limit contaminant transport through the vadose zone. A series of four intermediate‐scale flow cell experiments was conducted in homogeneous and simple layered heterogeneous porous medium systems to investigate the effects of heterogeneity on desiccation of unsaturated porous media. The permeability ratios of porous medium layers ranged from about 5 to almost 2 orders of magnitude. The insulated flow cell was equipped with 20 humidity and temperature sensors while a dual‐energy γ system was used to determine water saturations at various times. The multiphase code STOMP was used to simulate the desiccation process. For the layered systems, results show that injected dry gas flowed predominantly in the higher permeability layer and delayed water removal from the lower permeability material. For the configurations tested, water vapor diffusion from the lower to the higher permeability zone was considerable over the duration of the experiments, resulting in much larger relative humidity values of the outgoing air than based on permeability ratios alone. Acceptable numerical matches with the experimental data were obtained when an extension of the saturation‐capillary pressure relation below the residual water saturation was used. The agreements between numerical and experimental results suggest that the correct physics is implemented in the simulator.

Black Oil and Compositional Reservoir Simulation for Increasing the Recovery Performance of an Iranian Fractured Carbonate Reservoir

Naturally fractured reservoirs contain a significant amount of world oil reserves. Accurate and efficient reservoir simulation of naturally fractured reservoirs is one of the most important, challenging, and computationally intensive problems in reservoir engineering. Black oil and compositional reservoir simulators have been used to determine the reservoir management and production strategies to increase the oil recovery from a low-porosity, low-permeability fractured carbonate reservoir, with an average matrix permeability of 0.8 md, average fracture permeability of 500 md, and an average matrix porosity of 10%. This reservoir is a candidate for an enhanced oil recovery (EOR) process, because the reservoir production rate has been declined due to increasing the water cut as a result of rising the water oil contact. The injection techniques that have been considered in this study for black oil model include (a) gas injection, (b) water injection, and (c) simultaneous water alternating gas injection and for the compositional model include (a) dry gas injection, (b) CO2 injection, and (c) N2 injection. Simulation results show that CO2 injection has the maximum oil recovery between the EOR scenarios.

Removal of fracturing gel: A laboratory and modeling investigation accounting for viscous fingering channels

Gel damage in hydraulically fractured gas wells can be a serious problem if the accumulated gel is not removed after fracturing operations. During the fracturing process, polymeric gels are used to carry proppants into the propagating hydraulic fracture and the fracturing liquid is gradually leaked off into the formation by a percolation process while the gel accumulates in the form of a filter-cake. Removal of fluids from the porous, propped fracture can be accomplished by the displacement of the gel from the fracture. In this report we present a novel systematic study of the remediation of gel damage by an evaporative process that is enhanced by addition of volatile solvents. Addition of solvents such as alcohol is found to affect the gel saturation which is reduced due to the dehydration of gel. We conduct experiments of dry gas injection, along with solvent treatment, through a fractured tight gas sandstone core to improve the gas flowrate recovery. Additionally, we develop a mathematical model, based on drying front theory, to predict the rate of recovery of gas flowrates through the sand and fracture-packs. The mathematical model includes the effect of viscous fingering by considering a pack of one-dimensional systems with liquid saturations evolving independently. The gas flowrate recovery predicted by model is matched with the experimental data to obtain liquid saturation evolution within the porous systems. The resulting estimate shows that the fingering produces a smearing effect of the drying front. The model may then be used to predict the performance at larger scales for field applications.

Flow-Assurance Challenges in Gas-Storage Schemes in Depleted Reservoirs

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146239, ’Flow-Assurance Challenges in Gas-Storage Schemes in Depleted Reservoirs,’ by Alireza Kazemi, SPE, and Bahman Tohidi, SPE, Hydrafact Ltd., and Emile Bakala Nyounary, Heriot-Watt University, prepared for the 2011 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 6-8 September. The paper has not been peer reviewed. Injection or production of dry gas into or from a depleted gas reservoir could result in serious flow-assurance challenges. Parameters involved in water evaporation/production and in salt precipitation for a gas-production/-injection well are described quantitatively. The terms of formation damage (skin) were evaluated, and some recommendations for prediction and mitigation are proposed. Water in the produced gas is a major flow-assurance threat because of the possibility of gas-hydrate formation in the production system. Mitigation methods are presented. Introduction Gas injected into the depleted reservoir normally is a processed/dried gas. However, after injection, the gas is in contact with hydrocarbon and aqueous phases in the reservoir. Therefore, the composition of the produced gas may differ from that of the injected gas. More importantly, the produced gas will have some water (mainly in the form of vapor at reservoir conditions) because of the contact with water in the formation. During production, the water is produced with the gas. The net result is evaporation of water from formation brines, resulting in an increased formation-water salt concentration in the reservoir and salt formation/deposition. Also, the produced water may condense in the wellbore and/or surface facilities, resulting in corrosion, hydrate, and/or ice formation. Background The study model was a 3D, Cartesian-grid-type block containing one well. The model was intended to represent a portion of a gas field (i.e., drainage area) with its corresponding producer/injector. A seasonal natural-gas storage/production scheme was modeled. First, production from the reservoir lasted 30 months with a maximum daily gas-production rate of 45×106 m3/d. Then, injection was modeled for 3 months at 10×106 m3/d, followed by 4 months of soaking (i.e., shut-in). Then, for 5 years the following injection/production cycle was used: 2 months of production, 3 months of soaking, 3 months of injection, 4 months of soaking, and 2 months of production, for each calendar year. The following properties were assumed: Reservoir temperature=104°C, initial reservoir pressure=250 bar, average porosity=10%, horizontal permeability in x- and y-direction=100 md, vertical permeability=10 md, reservoir thickness=110 m, and reservoir dimensions of 900×900 m. Connate-water saturation was assumed to be 10%, with a gas/water contact at 1005-m depth. The reservoir gas was assumed to comprise four main components: methane (highest concentration), ethane, carbon dioxide, and water. The injected dry gas was assumed to have no water (i.e., 0% humidity). A modified Peng-Robinson equation of state was used in the simulation calculations.

Dry Gas Injection for Miscible Displacement on Žutica Oil Field

By the process of gas injection under miscible conditions, the (alai oil recovery also includes vaporized hydrocarbons from the residual immobile oil, in addition to the oil produced by direct displacement. The process is complex and involves the influence of the interaction of extracted hydrocarbons and in-situ oil at the displacement front. Therefore, the final oil recovery under miscible conditions is higher than the conventionally displaced oil. Methods of calculating multiple contacts miscibility with an Equation of State (EOS) determine the miscibility conditions by simulation processes as a vaporizing gas drive or condensing gas drive. The aim of this study was to determine a degree of miscibility.

Optimization of Production Gas Wells by Acidizing Using PLT Interpretation in Hassi R'Mel Field, Algeria

Abstract The Hassi R'Mel Field is a gas condensate reservoir with three Triassic sands (A-B-C) separated by a thick shale layer. Producing wells were drilled in the Northern-Central-Southern part with two lines of dry gas injection. A decrease in the production wells was observed. Build-up tests realized on those wells showed significant skin, which is due primarily to the excessive invasion mud used during drilling and workovers. A study was undertaken in order to see what method is to be used to optimize and improve the potential of these wells, which is less than hoped for given their petrophysic characteristics. Stimulation by acidizing was decided upon and three companies were selected to complete the program. During this program, 34 wells were acidized, which was carried out in three phases in order to diversify the methods. Of the 34 wells, 13 wells were chosen for the first phase, 13 wells for the second phase and the remaining eight wells were in the third phase. In order to study the stimulation's effects, PLTs were performed before and after each acidizing phase. The purpose of this paper is to show:The various methods of acidizing and the concentrations used in each of the three phases.Interpretations of the PLTs which enabled us to obtain flow layers, dynamic flowing pressure, static pressure, drawdown pressure and the productivity index in order to calculate the gain in production in each layer, the gain in production for each well and the flowing pressure. The combination of the PLT's results carried out on the acidized wells will be analyzed and shown in table form and graphs, which will enable us to draw a conclusion on the advantages and disadvantages of this stimulation program. Introduction Sandstone matrix stimulation has been the subject of extensive investigations for over 40 years and extensive experimental work has been conducted to investigate the reactions of various mud acid systems with damaging and formation materials(1–3). Theoretical analysis and modelling of the stimulation process have also been studied by some investigators(4–6). In this study, we wanted to share our experience of acidizing which was done in the Hassi R'Mel Field with different types of acids and various acidizing methods. The Hassi R'Mel Field is located 500 km southward from Algiers in the Algerian Sahara. It was discovered in 1956 and is one of the largest wet gas reservoirs in the world. This field has three distinct reservoir horizons: Zones A, Band C. Zone A sandstones are composed of very fine grained sandstones which are locally clay-rich with anhydritic cementing in some places. Zones B and C have very good reservoir quality with gas permeabilities ranging from 300 to 1,200 mD. Zone A also has very good reservoir quality, but its permeability is lower, at less than 300 mD. The productivity of Zones A, B and C has been reduced over time. Build-up tests performed on those wells had shown significant skin due to excessive invasion of mud used during drilling and workovers.

Modeling of Experiments on Water Vaporization for Gas Injection Using Traveling Waves

Summary Dry gas injected into wells will vaporize water from near the wellbore. The vaporization starts from the well and proceeds outward. Gas flowing to producers is in equilibrium with the reservoir brine, but water will be vaporized because the pressure drop that occurs toward the wellbore increases the ability of the gas to contain water. Thus, there are different mechanisms for injection and production. For both gas injection and gas production, vaporization concentrates solids in the brine that will precipitate into the formation when sufficiently concentrated. This paper reports on a combined experimental and theoretical analysis on the vaporization portion of this problem for dry gas injection. Experiments have been performed previously to determine the rate of water vaporization from Berea core samples at uniform initial water saturation (Zuluaga and Monsalve 2003). These experiments were performed by injecting dry methane into core samples that contained immobile water to represent water vaporization in a gas injector. Effluent water concentration curves showed two vaporization periods: a constant rate period and a falling rate period. The existence of a constant rate period means that the mass transfer within the core is occurring at conditions of local equilibrium. We interpret the falling rate period as the result of a moving capillary transition zone in which the amount of water vaporized decreases slowly because of capillary pressure effects. The falling rate period is the consequence of capillary imbibition of a wetting phase at very small saturation. We interpret the vaporization results with two traveling wave solutions. The first, which can be solved analytically, assumes that the capillary diffusion coefficient, D, and the volume fraction of water in the gaseous phase, Cwg, are constant. For this case, the results of the traveling wave solution are matched to the results of laboratory experiments by adjusting D. The second traveling-wave solution must be solved through numerical integration. In this case, the relative permeability scaling exponent is adjusted to match the laboratory experiments. The fitting provides insights into the nature of wetting phase flow at small saturation. Lastly, the experimental and mathematical procedure discussed in this paper is certainly a new method to obtain relative permeability exponents for the wetting phase at very low values of wetting-phase saturation (down to theoretically zero values).

Cleaning Up Water Blocking in Gas Reservoirs by Microwave Heating

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 101072, "Clean Up Water Blocking in Gas Reservoirs by Microwave Heating: Laboratory Studies," by Gao Li, Yingfeng Meng, SPE, and Hongming Tang, Southwest Petroleum Inst., China, prepared for the 2006 SPE International Oil & Gas Conference and Exhibition in China, Beijing, 5–7 December. Water blocking caused by fluid invasion during drilling, completion, and stimulation has been suspected of reducing or blocking gas-well deliverability. A technique that uses microwave heating to clean up water blocking in sandstone gas reservoirs is presented. Water-block cleanup by use of microwave heating is encouraging for field application, but further laboratory studies are required for the next phase of this project. Introduction Liquid will invade gas reservoirs when water-based fluids are used for drilling, completion, and stimulation. This water invasion will decrease the permeability, reducing flow capability or causing water blocking. Water blocking may lead to underestimating the gas-well productivity and reservoir value and to applying the wrong development strategy. Water blocking is a type of formation damage that restricts development of low-permeability gas reservoirs. Water blocking can be avoided or alleviated to some degree by use of underbalanced drilling, nonwetting-phase- and gas-based working fluids, and surface-tension-reduction techniques. After water blocking has happened, bypassing the damaged area may reduce the degree of damage (e.g., deep-penetration perforation, fracturing, and acid fracturing). Decreasing the water saturation of damaged areas (increasing drawdown, dry-gas injection, or extending shut-in time) or decreasing surface tension also may be effective. However, these methods cannot relieve water-block damage completely. Formation-heating technology (FHT) can improve the crude-oil fluidity, dehydrate clay, and enhance near-wellbore formation permeability and can be used to remedy water blocking by injecting hot gas to heat the formation near the wellbore. FHT has been tested and applied in oilfield production. However, FHT uses heat conduction and convection in the rock and gas to heat the formation. Because the heat capacity of gas is limited and heat conduction through rock is slow, the heating process is slow and inefficient. Microwave heating can heat materials rapidly and efficiently. Microwave heating is used to increase fluidity of heavy oil and to produce gas hydrate. This paper studied the influence of microwave heating on sandstone gas reservoirs and the feasibility of clearing water blockage. Basic Microwave Heating Microwaves are extremely high-frequency electromagnetic waves with a wavelength between 1 mm and 1 m and frequency from 300 GHz to 300 MHz, respectively. Used on dielectric materials, microwaves can cause electronic polarization or atomic polarization, interfacial polarization, and dipolarity turning to polarization. The polarization of dielectric materials can cause power dissipation, which raises the material's temperature. Conventional heating depends on heat conduction, convection, and radiation with slow heating from external to internal, while microwave heating can heat both the internal and the external at the same time with high heating speed and efficiency. Microwave energy can trans-form into heat energy instantaneously.

Gas Injection EOR- A New Meaning in the New Millennium

Abstract Although the idea of injecting gases to improve oil recovery has been known for over three-quarters of the past century, it appears to be taking on a new meaning as we step into the new millennium. The oil price scenario remains consistently loyal to its rollercoaster past; the long awaited jump in the natural gas price has become a reality; the oil industry has made new strides in horizontal drilling with significant cost reductions; and the world's attention is focused on the industrialized nations to lead the way to control global warming by reducing greenhouse gas emissions. These evolving global issues combined with the ever-declining reserves of conventional crude oils appear to bring a new optimism to enhanced oil recovery (EOR) by gas injection. Added to this optimism are the well-accepted facts that waterflood recoveries from conventional oil reservoirs rarely exceed 40﹪ of the original oil in place (OOIP); that most waterfloods are maturing or close to their economic limits; and that chemically enhanced waterfloods appear to have become practically extinct in spite of their conceptual soundness. Therefore, gas-based EOR processes using horizontal wells appear to be the solitary hope for continuing profitable production from the large remaining reserves of conventional oil in Canada, the United States and the rest of the world. In what follows, we will briefly discuss-but not review-the conceptual basis for gas injection EOR processes and what we have conveniently overlooked in it, the historical developments, process design considerations, problem areas, and the future direction and potential of this time-tested technology. The Background The concept of injecting gases into reservoirs to improve oil recovery is an old one, dating back to the 1920s when the early research papers appeared. However, much of the progress in our knowledge of the physics and chemistry of multiphase flow through porous media seems to have occurred after the early 1950s. This progress encompassed the development of three main processes of enhanced oil recovery (EOR): thermal, chemical, and miscible. While the thermal EOR process and its variations were aimed mainly at recovering heavy oils by lowering their viscosity to enable their flow, the chemical and miscible gas processes targeted the light and medium gravity crude oils by lowering the interfacial tension between the injected fluid and the crude oil to minimize the trapping of oil in the rock pores by capillary or surface forces. Before discussing the background of gas injection EOR processes, we need to distinguish the term EOR from the more recent term of improved oil recovery (IOR). The EOR processes involve the injection of fluids to supplement the natural energy in the reservoir to displace oil to the producing wells. More importantly, the injected fluids interact with the reservoir rock-fluids system to create conditions favourable for enhancing oil recovery. These favourable interactions include oil swelling, interfacial tension reduction, oil viscosity reduction, rock wettability modification, and phase behaviour effects(1). Thus, simple waterflooding and dry gas injection for pressure maintenance are not EOR processes, as they do not involve any of these interactions.

The migration fractionation: an important mechanism in the formation of condensate and waxy oil

Fault-initiated pressure release within reservoirs and the injection of external excessive dry gas may result in occurrence of oil and gas phases. Because of different partitioning coefficients of compounds in two phase flow, lower-molecular-weight components are easier to dissolve in gas phase, yielding condensates, while higher-molecular-weight components are retained in the oil phase, yielding waxy oil cumulations. The fractionation process causes extensive compositional variability in aliphatic/aromatic hydrocarbon ratios, molecular compound distributions and carbon isotope ratios that are traditionally considered to be related to the source organic matter or the thermal maturity.

Drilling of Arun Gas Field

Summary The Arun gas field was discovered in late 1971 when the discovery Well Arun A-1 penetrated the thick Arun limestone reef. During the following 3 years, 12 delineation wells were drilled. Three of these delineation wells are used for observation wells, five for dry gas injection, one for condensate water disposal, and three are abandoned. Clustered development well drilling started in Sept. 1976. At this writing 40 wells have been drilled to delineate and develop the field. Drilling continues so that the growing demand from the expanding liquefied natural gas (LNG) plant is met. The problems of high temperatures, abnormally high-pressured shales, and saltwater sands overlying the lower-pressured Arun limestone have been conquered by numerous technique changes. The current techniques include the use of inverted oil emulsion muds, cements containing 35% silica flour, high-strength heavyweight tubulars, and clear packer fluids. The evolution of drilling and completion practices are discussed in the paper. Introduction The Arun gas field is located in the northern portion of Sumatra, Aceh Province, which lies within Mobil Oil Indonesia Inc. Block B production sharing contract area (Fig. 1). It was discovered in 1971 by the drilling of Arun A-1 in the thickest part of the Arun limestone reef close to the present Cluster III location. Cluster development drilling (Fig. 2) started in Sept. 1976. Currently two clusters (Clusters II and III) have been developed with the third cluster (Cluster I) development started in 1981. The fourth cluster development (Cluster IV) started in 1983 to meet the growing demand for the expanding LNG plant. Cluster drilling is used to centralize and consolidate the surface facilities for safety and security reasons and to reduce the disruption to rice growing in the area of the gas field. Provision is made on each cluster for a maximum of 16 producing wells located in two lines of eight locations on a 262-ft [80-m] spacing along the eastern boundary of the cluster with about one-half of the cluster area allocated to the locations. Initially up to eight wells are drilled in each cluster, the remaining locations to be drilled when additional producing capacity is required. The gas processing and compression equipment occupies the western half of the cluster. The entire cluster is surrounded by a dike and antipollution ditch and completely fenced with night lighting and a staffed security building at the cluster entrance. The development wells are deviated out from the clusters (Fig. 2) to drain the reservoirs effectively along the axis of its structural high. Gas injection wells are generally drilled vertically on the western flank of the reservoir to recycle the excess dry gas after the condensate has been recovered. Drilling Problems Associated With Geology Drilling problems are associated with the high temperatures and abnormally high-pressured shales and saltwater sands overlying the high-pressure Arun limestone gas reservoir. The Arun field gas reservoir is a and of Early and Middle Miocene age located near the base of the tertiary sedimentary section. The gas accumulation is mainly stratigraphic, having been trapped in a porous reefoid facies overlapped by the Baong shales (Fig. 3). The Baong shales are abnormally high pressured and are overlain by the Keutapang formation, which exhibits a pressure transition zone grading into an abnormally high pressure. The Keutapang formation contains a number of high-pressure gassy saltwater sands, and above the Keutapang pressure transition zone the pore pressures of the formation are normal (Fig. 4). The Arun limestone reservoir pressure, although lower than the Baong shale, is abnormally high, being originally 7,100 psi [49 mPa] at 10,000 ft [3048 m] subsea. The gas contains 13.75% CO2 and 0.005 to 0.01% H2S. The static bottomhole temperature (BHT) is 352 deg. F [178 deg. C]. This high BHT is also reflected in the overlying Baong shale and Keutapang formation, which exhibit high temperature gradients. The high temperatures and pressures require weighted mud capable of retaining its properties to allow successful drilling and casing operations. The cement slurries must be capable of allowing the casing to be single-stage cemented to surface and to exhibit a high compressive strength. Surface and intermediate casing setting depths must be selected to ensure that loss or flow problems do not occur. The changes in temperature during production require casing tension landing techniques to avoid buckling. The CO2 and H2S content of the Arun gas requires special high-grade production tubulars and wellhead equipment to resist corrosion and erosion at high production rates. Discovery and Delineation Drilling JPT P. 771^

Oil recovery by gas injection including gas miscible displacement.

This paper researches the efficiency and production performance of oil recovery by gas injection including miscible gas displacement process in an actual low permeability reservoir. Phase behaviors of injected gases and production performances are investigated on two gas injection processes of dry gas injection and enriched gas injection into an actual oil reservoir with a primitive mathematical model, which can hadle both immiscible and miscible gas displacement processes. As a result, it is concluded that enriched gas injection will give better oil recovery owing to the miscible displacement process occurring near the injection well for the case of oil presented in the sample calculations.

Unique Enhanced Oil and Gas Recovery for Very High-Pressure Wilcox Sands Uses Cryogenic Nitrogen and Methane Mixture

Summary Primary recovery is low for the volatile oil and retrograde condensate reservoirs in the hot, high-pressured, multilayered Wilcox sands in the Fordoche field, Point Coupee Parish, LA. Recovery from oil reservoirs by depletion is predicted by numerous model studies to be 26 to 36% of the OOIP. Condensate recovery by depletion is predicted to be 19% of the original condensate in place and 25% of original separator gas in place. The injection of dry natural gas at high pressures will result in a miscible displacement of reservoir fluids. The immiscible displacement of reservoir fluids. The injection of a mixture of nitrogen and dry gas is predicted to be as effective as injecting dry natural gas. Model studies of gas injection in volatile oil reservoirs predict recoveries from 47 to 54% of the OOIP, and in the retrograde condensate reservoir recoveries are predicted to be 30 and 46% of the original condensate and gas in place. Oil recovery studies at 6,955 psig indicate that gas injection will displace 89% at breakthrough and 93% at blowdown at 100% sweep efficiency. A well stimulation program has been developed that results in a 2.5-fold increase in production rates. Introduction The Fordoche field was discovered by Sun Oil Co. in 1966. The location is shown in Fig. 1. The field was developed fully on 160-acre well spacing by 1970. A total of 36 wells was drilled during the short 4-year development period. Well depths ranged from 11,800 to 16,500 ft (See Fig. 2, a typical log for the Fordoche field.) Seven reservoirs encountered between depths of 11,300 to 13,900 ft had initial bottomhole pressures (BHP's) ranging from 8,372 to 11,018 psig and bottomhole temperatures (BHT's) ranging from 226 to 278°F. The Sparta sands are undersaturated oil reservoirs. The Wilcox 4 and 5 (W-4 and W-5) sands are gas-condensate reservoirs. The W-8, W-12, and W-15 sands are undersaturated volatile oil reservoirs. All of the Wilcox reservoirs experienced rapid rates of reservoir pressure depletion. Productivity of all wells declined severely. After evaluating water injection and gas injection programs, high-pressure gas injection was selected for the two major oil reservoirs, W-8A and W-12A, and for the largest retrograde reservoir, W-5A. (See Figs. 3, 4, and 5). A very high-pressure miscible gas injection project was instituted to maintain pressure and well productivity and to enhance ultimate recovery. Initially, extraneous gas was purchased for makeup and injected with the processed natural gas produced in the field. Because of the increasing cost of natural gas and the restricted oil price of $5.35 per barrel, economics dictated that the project be changed to a partial pressure maintenance program with a lower ultimate recovery or find a substitute for natural as used for makeup.

Economic Evaluation of Cycling Gas-Condensate Reservoirs With Nitrogen

Summary This work presents the results of an investigation of the economic feasibility of using cryogenically produced nitrogen as a substitute for natural gas to maintain reservoir pressure during cycling operations in gas-condensate reservoirs. Those economic factors unique to nitrogen cycling are discussed. It has been concluded that gas reservoirs with a condensate content in excess of 100 bbl/MMcf should be considered as potential nitrogen cycling prospects. Introduction Historically, gas-condensate reservoirs which exhibit liquid loss through retrograde condensation with reduction in reservoir pressure have been depleted under a full or partial pressure maintenance program by injection of dry natural gas. The technology to evaluate and accomplish this is available and well proved. The increased value and the shortage of natural gas, however, has made it generally uneconomic to divert this gas from the sales line to injection for the purpose of maintaining pressure in gas-condensate reservoirs. This paper is concerned with the economic feasibility. of using cryogenically produced nitrogen as a substitute for natural gas to maintain reservoir pressure during cycling operations in gas-condensate reservoirs. Many factors affect the economics of a gas cycling project. Generally, the three most important factors are prices, stock-tank liquid content of the reservoir gas, and the degree of reservoir heterogeneity. For the purpose of this evaluation, a hypothetical reservoir has been defined. Projections of performance have been made assuming the reservoir contains three different reservoir fluids with stocktank liquid contents ranging from 76.1 to 220.7 bbl/MMcf. The performance of each of these reservoir fluid systems has been evaluated assuming three different degrees of reservoir heterogeneity. Performance and economic projections have been made assuming three different depletion methods:pressure depletion with no injection,pressure maintenance by nitrogen injection, andpressure maintenance by return of residue gas and purchase of makeup gas. Multiple projections have been made for the injection cases assuming blowdown of the reservoir is initiated at various times, starting with breakthrough of dry gas. Performance and economic results are presented for those cases which produce the maximum income discounted at a rate of 15070 per year. Economic evaluations were made assuming prices and costs escalate at a rate of 6070 per year. Projections of Performance Reservoir Description To make an economic evaluation of cycling a gas-condensate reservoir with nitrogen, it was necessary to obtain projections of reservoir performance. It was our desire to evaluate the effect of different reservoir fluid compositions and degrees of reservoir heterogeneity upon the economic potential of this depletion mechanism. To isolate these effects, performance projections were made on a hypothetical reservoir whose properties are shown in Table 1. The hypothetical field contained six contiguous five-spot patterns of 360 acres each. This resulted in a conforming area under injection operations of 2,160 acres or 75070 of the total field area. In all injection cases investigated there were six injection and 12 producing wells. Under pressure depletion it was assumed that there were 18 producing wells. Reservoir Fluid Properties The compositions and basic properties of the three reservoir fluids investigated are presented in Table 2. Reservoir Description To make an economic evaluation of cycling a gas-condensate reservoir with nitrogen, it was necessary to obtain projections of reservoir performance. It was our desire to evaluate the effect of different reservoir fluid compositions and degrees of reservoir heterogeneity upon the economic potential of this depletion mechanism. To isolate these effects, performance projections were made on a hypothetical reservoir whose properties are shown in Table 1. The hypothetical field contained six contiguous five-spot patterns of 360 acres each. This resulted in a conforming area under injection operations of 2,160 acres or 75070 of the total field area. In all injection cases investigated there were six injection and 12 producing wells. Under pressure depletion it was assumed that there were 18 producing wells. Reservoir Fluid Properties The compositions and basic properties of the three reservoir fluids investigated are presented in Table 2.

Design of a Definitive Field Pilot Test of Rich Gas Drive Recovery, Willmar Field, Saskatchewan

Abstract Implementation of hydrocarbon miscible flood operations in the Willmar Field, Saskatchewan, requires a preliminary field test to define the design parameters, such as slug size and enrichment required, as well as to estimate how much additional oil may be recovered. The planning and initiation of a 4-hafive-spot pilot test is discussed, including the gathering of in-situ reservoir data, design of facilities having a high data acquisition frequency, reservoir engineering calculations and operating plans. The project work has already revealed some unexpected results, and greater insight into reservoir performance under miscible displacement is expected. Introduction The implementation of a field test blends business and technical viewpoints. For the test to be useful, results must be derived to explain how the miscible process works, indicate how it can be optimized and define design parameters (slug size, enrichment, gas/water ratio, etc.) for use in installing a full-scale scheme. From the business viewpoint, cost-effective equipment design and operation and effective use of government incentives must play significant roles. Planning must also include derivation of a reservoir performance base for the pilot, against which the final results can be compared quantitatively. Miscible flood is the only type of enhanced recovery process currently attractive for Western Canada carbonate reservoirs, because commercial thermal, chemical and polymer processes are not predicted to improve reservoir performance. Sources of natural gas liquids, non-associated gas and pure carbon dioxide are limited in southeastern Saskatchewan, so plans were made to generate miscible fluid from the produced oil. Free gas saturations can be expected to develop as a result of replacement of methane by intermediates, so -alternate water and gas injection is planned to control gas breakthrough. After initial waterflood to provide a data base and placement of the initial rich gas slug, dry chase gas injection is planned to enable natural gas liquids to be recovered, followed by waterflood to depletion. Reservoir Characterization The Willmar Field comprises several pools containing under saturated oil trapped beneath the regional Mississippian unconformity. The most southwesterly reservoir underlying a 400-ha area in Sections 31 and 32-5-3W2, shown ill Figure 1, was chosen for further study, The reservoir quality and performance, described in Table 1, suggested a high likelihood for obtaining meaningful pilot results(1). Development on 30-ha spacing has yielded 14 producers, completed primarily in the Lower Porosity(2), shown in Figure 2. Water production has steadily increased in Sections 31 and 32-5-3W2, as shown in Figure 3, and all wells now produce water. No substantial increases in gas-oil ratio have occurred. Pool History The early production history for the pool indicates depletion drive to predominate, with pressure decline from 11.7 MPa(3) initially to 9.2 MPa during the first six years. Natural water influx\ has since provided 80% of the reservoir energy. Pool production rates increased with development to 100 m3 /d(4) in 1969, but have since declined as water-oil ratios increased. The water influx has been primarily from the northwest, where water-oil ratios average 5.6 m3/m3 compared to 0.6 m3/m3 in the southeast part of the pool.

Enriched-Gas Miscible Flooding: A Case History of the Levelland Unit Secondary Miscible Project

Performance is reviewed of an enriched hydrocarbon-gas Performance is reviewed of an enriched hydrocarbon-gas miscible-displacement process in the Levelland Unit. Cyclic injection of enriched gas and water has been in progress for about 4 years. No significant operational problems have been encountered. The project is experiencing response, but peak response has not yet been reached. Performance indicates this project will be an economic success. Performance indicates this project will be an economic success. Introduction The Levelland Unit secondary miscible project consists of 28 injection wells and 40 producing wells in the west central portion of the Levelland Unit, Levelland field, Hockley County, Tex. (Fig. 1). Production is from the San Andres formation at an average depth of 4,900 ft. The discovery well for this reservoir was drilled in 1946. The field was developed originally on a well spacing of 42.5 acres/well. In 1954, the Levelland Unit was formed to conduct secondary recovery operations. A pressure maintenance program was initiated in 1955, consisting of dry gas program was initiated in 1955, consisting of dry gas injection into 18 wells scattered within the unit. Three of these former dry gas injectors are located in the secondary miscible project. All dry gas injection operations had ceased by Feb. 1971. Water injection was initiated in parts of the Levelland Unit in Oct. 1964; however, water parts of the Levelland Unit in Oct. 1964; however, water injection in the area that became the secondary miscible project did not begin until later. project did not begin until later. In April 1970, the west central portion of the Levelland Unit was evaluated for infill drilling and possible miscible flooding. Infill development would establish a well spacing of 21.25 acres/well and was justified for either the straight waterflood case or for a miscible-flood case. All the proposed infill drilling has been completed. Original plans included miscible flooding of the entire west central portion of the unit. This was to be done in two phases beginning with 28 injection wells in the Phase 1 phases beginning with 28 injection wells in the Phase 1 area, with the remaining wells to the south to be converted at a later date; however, because of supply limitations of enriched gas, the Phase 2 area has remained on waterflood. Enhanced recovery will not take place in the Phase 2 area as a secondary operation. If enhanced recovery takes place as a tertiary-type operation, it most likely will be a place as a tertiary-type operation, it most likely will be a CO2 miscible flood rather than hydrocarbon miscible because of an insufficient additional supply of enriched gas. P. 919

Recovery of Retrograde Condensed Liquids By Revaporization During Dry Gas Injection

Abstract Laboratory experiments were conducted to determine the rates of revaporization of the immobile liquid that was deposited in 'Various porous media as a result of retrograde condensation during pressure depletion of methane n-butane mixtures. The influence of particle size, initial liquid saturation, dry was injection rate and immobile water saturation on the revaporizution process was studied by measuring effluent concentration profiles as a function of volume of methane injected. The revaporization rate was estimated by matching the solution of a Mathematical model, in which mass transfer is expressed by a first-order rate expression, to the experimental effluent concentration data. In general, the rate of mass transfer was found to increase with decreasing particle size of the porous medium, increased condensed liquid saturation and increased immobile water saturation. The increase in each case is attributed to increasing the interfacial area between the gas and the condensed liquid. The magnitude of the measured 1nass transfer rates indicates that thermodllna1nic equilibrium between flowing gas and liquid could be assumed. Introduction WHEN FACED with the problem of planning production operations for gas condensate reservoirs, engineers frequently wish to compare the fluid recoveries and cash flows for various exploitation schemea(1). The simplest scheme consists of continuous pressure depletion or "blow down" to abandonment pressure. This method is attractive because:it requires low initial capital investments,it provides high initial cash flows andit requires the least engineering design. The deficiencies of this process are:loss of valuable condensate liquids resulting from a continual decrease in volatility as the average molecular weight of the reservoir fluid increases during the depletion (2,3,4);large variations in loading of the gas plant during the life of the project(3); andhigh liquid accumulation in the vicinity of the production wells with resulting lowered deliverabilities(3). Another exploitation scheme which is commonly used is gas cycling 'With full pressure maintenance. In this method, gas cycling is initiated at the start of production. The average molecular weight of the reservoir fluid decreases as it is diluted with dry injection gas. After breakthrough of dry gas at the production wells, pressure depletion by blow down is allowed to occur. The advantages of this method are:displacement of dense upper-dew-point fluids by dry gas results in high recoveries for swept portions of the reservoir;the accumulation of liquids in the vicinity of the producing wells is inhibited both during the gas injection and the pressure decline phases of operation;in the case of injection into a gas cap in which there is an immobile residual oil saturation, much of the oil may be recovered by vaporization(5,6). The disadvantages(3) of this method of operation are:high initial and operating costs for gas handling facilities;low cash flows resulting from deferred gas sales (7), and make-up gas purchases. Several variations of these two basic processes have been discussed in the literature(3, 5, 8, 1, 9, 7).

Effect of Including Composition-Dependent K Values To Generate Data for a Modified Beta-Type Simulator (includes associated papers 6418 and 6419)

JPT Forum articles are limited to 1,500 words including 250 words for eachtable and figure, or a maximum of two pages in JPT A Forum article maypresent preliminary results or conclusions of an investigation that theauthor wishes to publish before completing a full study; it may impartgeneral technical information that does not warrant publication as afull-length paper. All Forum articles are subject to approval by an editorial committee. Letters to the editor are published under Dialogue, and may cover technical or nontechnical topics. SPE-AIME reserves the right to edit letters for style and content. Introduction Cook et al. presented a modified beta-type reservoirsimulatorforapproximatingcompositionaleffectsduring simulation of dry-gas injection into an oil orrich-gas-condensate reservoir. A composition parameterrepresenting the cumulative volume of dry gas per volume of oil(G) was incorporated into a standard beta-type simulator to make that simulator behave as a compositional modelwith a reported substantial reduction in computer time.The composition parameter and fluid properties requiredby the beta-type simulator were obtained from a linear cell-to-cell model. The parameter was plotted vs thefluid properties, and the result was a set of curves for eachfluid property that was independent of cell number in thelinear model. Therefore, the curves would beindependent of the space dimension in a reservoir model.This was important because incorporating position-dependentcurves into a beta-type model would significantly complicate this model, resulting in a loss of model simplicityand computer-time advantage. The cell-to-cell model used by Cook et al.incorporated K values that were a function of pressure only; theK values were independent of fluid composition. Theauthors suggested their model for simulation of drygas injection. However, the results presented are for arelatively rich gas (9.3 1-percent C -C). Compositiondependence of K values would be minimal for this gas, which supports the fair agreement between performancepredicted by the modified beta-type model and thecompositional model. For complex fluid systems, such as dry-gas injectioninto a volatile oil or a rich-gas condensate, K values arehighly dependent on fluid composition. This paperpresents results demonstrating that composition-dependent K values yield fluid properties that are dependenton cell number or location within the reservoir.Consequently, the modified beta-type model should not be usedfor reservoir simulations where large changes in fluidcomposition are anticipated. Discussion A study was initiated to determine the effects ofcomposition-dependent K values on reservoir propertiesduring dry-gas injection into a volatile oil reservoir.The gas and oil compositions and their physical properties aregiven in Table 1. A cell-to-cell model, similar to the oneused by Cook et al., was used to obtain the compositionparameter. Gi, and the phase properties. This modeldiffered from Cook et al.'s, however, in that it used theRedlich-Kwong equation of state matched experimentallyequilibria. The equation of state matched experimentallydetermined volumetric data of the volatile oil and ofmixtures of a lean gas with the gas condensate thatis in equilibrium with this oil at reservoir conditions, The matching of these volumetric data results incomposition-dependent K values; and to match thesedata, composition-dependent K values were predicted by the equation of state. These results suggest the equationof state can be used to simulate dry-gas injection into thevolatile oil. The computation logic of the cell-to-cell model hasbeen presented in Refs. 4 and 5. Each cell of the modelused in this study contained 1 bbl of equilibrated reservoiroil at the reservoir temperature of 265 deg. F and a pressure of4,000 psia. JPT P. 1180^