Acid Gas Disposal Research Articles

Influence of dissolution on long-term frictional properties of carbonate fault gouge

Velocity stepping experiments have been performed on a simulated calcite gouge using an annular shear apparatus to investigate the effect of dissolution on the frictional properties of a carbonate fault. The tested material was put in contact with hydrochloric acid at different concentration in order to provoke grains dissolution prior to the experiments. Particle size analysis shows that the small grains tend to disappear due to the chemical reaction, whereas the distribution of large grains is not much affected. The dissolution process induces a decrease of the fractal number of the grain size distribution and an increase of the roughness of the particles. The study of the rate-and-state parameter of the materials, which is commonly used to characterize the ability of the fault to generate earthquakes, shows a decrease towards more negative values with dissolution for dry specimens and an increase for wet samples. Moreover, a decrease of the steady state friction coefficient is observed with dissolution for wet samples. This decrease of the friction would promote the triggering of slip along an existing fault after the injection of an acid fluid like in the cases of CO2 storage or acid gas disposal projects in a carbonate reservoir, but the increase of the rate and state parameter (a–b) of saturated specimens implies that the seismogenic potential of faults could potentially be reduced.

Numerical simulation and feasibility assessment of acid gas injection in a carbonate formation of the Tarim Basin, China

An enormous amount of acid gas, containing carbon dioxide (CO2) and hydrogen sulfide (H2S), is generated in the exploitation of oil and gas reservoirs in the Tarim Basin, China. An appropriate management plan is required to safely dispose of the acid gas, and common strategy considered for the safe disposal of acid gas is the injection of it into deep formations – this strategy mitigates greenhouse gas emissions and avoids costs associated with desulfurization. A feasibility assessment of acid gas injection requires a detailed investigation of the potential physical and geochemical impacts. Reactive transport simulations based on the mineralogical composition and the hydrochemical characteristics of a carbonate formation in the Tarim Basin were conducted to identify the physical and geochemical interactions of acid gas with the mineral matrix and formation water. Acid gas (59% CO2 and 41% H2S) was injected at a constant rate of 19 200 Nm3/d for 25 years, and the simulation was run by the TMVR_EOSG module of the TOUGHREACT code for a period of 10 000 years. The results indicate that the minimum liquid saturation is much larger than the residual water saturation, and the pressure buildup is below the allowable pressure increase. Additionally, the porosity change is found to be negligible due to the small changes in calcite and quartz in the volume fraction. From this perspective, acid gas injection in the carbonate formation of the Tarim Basin seems feasible. Furthermore, the fast breakthrough of CO2 can provide an advanced warning of a potential breakthrough of acid gas. Last, the injection rate can be increased to accelerate acid gas trapping, and the results could be used as guidance for future acid gas injection operations.

Sustainable Design and Synthesis of Shale Gas Processing and Chemical Manufacturing Processes

In this work, we propose a superstructure of integrated shale gas processing and chemical manufacturing processes with 51,840 alternative possible process designs. The superstructure consists of eight sections, namely acid gas removal, dehydration, NGLs recovery, NGLs separation, hydrocarbons conversion, light olefins separation, C4 separation, and acid gas disposal. For the steam cracking reactions in the hydrocarbons conversion section, we optimize the product distributions of steam cracking of ethane, propane, n-butane, and i-butane. Extensive process simulations are performed for all the involved processes in the superstructure in order to collect high-fidelity process data and develop detailed process models for the technology/process alternatives in the superstructure. Next, we propose a multiobjective mixed-integer nonlinear programming (MINLP) superstructure optimization model with five groups of constraints, namely superstructure network configuration constraints, mass balance constraints, energy balance constraints, techno-economic evaluation constraints, environmental impact assessment constraints. Three objective functions are maximizing the net present value per GJ of raw shale gas, minimizing the global warming potential per GJ of raw shale gas, and minimizing the water footprint per GJ of raw shale gas, respectively. A tailored global optimization algorithm is applied to efficiently solve the resulting nonconvex MINLP problem. The application of the proposed framework is illustrated through a case study based on a Marcellus shale gas feed.

Gibbs Free Energy Minimization for Prediction of Solubility of Acid Gases in Water

The disposal of acid gas (CO2/H2S mixtures) is a critical aspect in the production of hydrocarbons from sour gas fields. The increasing emphasis on CO2 sequestration has also renewed interest in the disposal of flue gas mixtures (primarily containing CO2 and H2S). A common strategy for safe disposal, in either case, is to inject the acid gas in aquifers close to production plants. These strategies rely on solubility calculations at different pressures and temperatures, governed by the field operating conditions. We present a comprehensive approach using Gibbs free energy minimization to calculate acid gas solubility in water at high temperatures (298–393 K) and pressures (0.1–80 MPa). The advantage of this approach is the flexibility to use different thermodynamic models for different phases. The proposed model uses the Peng–Robinson (PR) Equation of State (EOS) description for gas components while the liquid components are described using the ideal assumption for the temperature range 298–323 K and the Nonrandom Two-Liquid (NRTL) activity coefficient model at temperatures greater than 323 K. The model predictions compare well with experimental data for binary (CO2–H2O and H2S–H2O) and ternary mixtures (CO2–H2S–H2O). The model can also be easily extended to predict the solubility of any gas in water as well as brine containing ions to incorporate geochemical reactions.

Geologic modeling and fluid-flow simulation of acid gas disposal in western Wyoming

The Moxa arch anticline is a regional-scale northwest-trending uplift in western Wyoming where geologic storage of acid gas (carbon dioxide, methane, nitrogen, hydrogen sulfide, ethane) is under consideration. Nugget Sandstone, a deep saline aquifer at depths exceeding 17,000 ft (5180 m), is a candidate formation. This study builds three-dimensional local- to regional-scale geologic and fluid-flow models for the Nugget Sandstone and its neighboring formations. Geologic and engineering characterization data were assembled and screened for accuracy. Using geostatistical simulations (first, sequential indicator simulation of facies, then the sequential Gaussian simulation of porosity []), the data were integrated to create a regional-scale geologic model from which a local-scale simulation model surrounding the proposed injection si te was extracted. Using this model, acid gas injection was simulated for 50 yr, followed by 1950 yr of monitoring. A sensitivity analysis was conducted, exploring the impact of geologic and engineering variables on model predictions. Results suggest that, at the simulation time scale, low dissolved solids in formation water, large gas-phase relative permeability (krg) hysteresis, and low vertical-to-horizontal intrinsic permeability (k) anisotropy all contribute to enhanced storage of acid gas in both residual (trapped) and dissolved forms. The parameter that exerts the largest control on gas storage is relative permeability hysteresis. However, given parameter uncertainty, the total predicted gas storage varies significantly. Prediction uncertainty increases in the order of dissolved gas, trapped gas, and mobile gas. In comparison, petrophysical uncertainty, as represented by multiple realizations, has limited impact on prediction, although future work is needed to expand the uncertainty analysis by developing alternative facies models for the storage formations.

Analysis of potential acid gas leakage from wellbores in Alberta, Canada

Deep geological disposal of acid gas reduces green house gas emissions and removes potentially toxic hydrogen sulphide from the accessible environment. Leakage of acid gas through abandoned wellbores could compromise greenhouse gas mitigation and could be toxic. In this study, simple analytical equations are developed to predict the worst case, post injection leakage rate from wellbores with intact casings such that the acid gas moves directly from the reservoir to the surface with no dissolution into surrounding formations. The U.S. EPA code, ALOHA and Lawrence Livermore code, SLAB, are used to estimate atmospheric concentrations of hydrogen sulphide for worst case acid gas leakage at two sites west of Edmonton, Alberta; one in the Pembina-Wabamun area and the other in Brazeau-Nisku area. Results indicate detrimental atmospheric concentrations at low wind speeds would be confined to within about 3.5km downwind for the Nisku site. Lethal concentrations would be confined to within about 10m downwind for the Wabamun site and about 30m downwind for the Nisku site.A semi-analytical model is used to predict long-term leakage rates and concentration of dissolved acid gas in formation fluids surrounding a wellbore with leakage through a failed casing at a site near Wabamun Lake. Two sequestration processes: geochemical reaction and convective mixing in the reservoir are shown to be important in decreasing the duration of long-term leakage from thousands of years to hundreds or years. Leakage confined to the annulus of the wellbore could result in complete acid gas dissolution into surrounding formations with no atmospheric leakage. The Joule–Thomson cooling effect is shown to be unimportant for passive leakage. Concentrations of dissolved acid gas above the odour and taste threshold could occur in potable aquifers such as the Paskapoo. Contamination of potable aquifers with heavy metals could not be ruled out.

Chromatographic Partitioning of H2S and CO2 in Acid Gas Disposal

Abstract Hydrogen sulfide breakthrough in producing wells occurred after the breakthrough of CO2 in the Long Coulee Glauconite F reservoir in southern Alberta, where acid gas (98% CO2, 2% H2S) has been injected since 2002. It was hypothesized that the preferential solubility of H2S in formation brine is responsible for the delay in H2S breakthrough. To study the chromatographic separation of H2S and CO2, a series of experiments were conducted to measure the solubility of CO2 and H2S in formation brine at in-situ conditions. Immiscible displacement experiments were performed in a slim tube packed with silica sand to study the breakthrough behaviour of different gas components. The experiments were then modelled using a compositional simulator, and the effect of different factors on the delayed breakthrough of H2S was examined using a series of sensitivity studies. It was confirmed that the preferential solubility of H2S over CO2 leads to it being stripped off at the leading edge of the gas displacement front, resulting in its delayed breakthrough. A similar delay in H2S breakthrough occurs even at higher H2S concentrations (e.g. 30%) in the injected gas. Through the simulation studies it was shown that the delay in H2S breakthrough becomes more pronounced if the gas front is more diffusive. For example, it was shown that, when gravity forces or mobility ratio favour stable displacement, CO2 and H2S breakthroughs occur closer to each other. This is of significance, particularly for monitoring of impure CO2 storage in deep saline aquifers, where the impurity may consist of H2S. Detection of CO2 at a monitoring well would indicate that the more noxious H2S is likely to show up after some time lag. This paper describes the experiments and the simulation studies and presents the implications of the chromatographic partitioning of H2S and CO2 for geological storage of acid gas or impure CO2.

The Legal Framework for Carbon Capture and Storage in Alberta

Carbon capture and storage (CCS) technologies are gaining currency as a means of disposing of greenhouse gases and helping states meet their international obligations under such instruments as the Kyoto Protocol. However, while the utility of these technologies has become increasingly evident, their relative novelty has meant that the legal issues surrounding their application have remained largely unresolved. This article examines the property, regulatory, and liability issues associated with CCS in an Alberta context. The authors draw upon existing law and practice in relation to analogous activities including enhanced oil recovery, acid gas disposal, and natural gas storage to identify changes and clarifications that might be desirable in order to develop an appropriate legal framework for CCS in Alberta.

Simulation Study of Acid Gas Injection Into an Aquifer

Abstract A series of simulation runs using a compositional simulator were conducted to determine the area of influence that results from injecting acid gas (H2S) for 30 years at 330 e3m3 into a 75 m thick high permeability sandstone aquifer. In this study, the three-phase (gas-oil-water) equilibrium calculation was used. Initially, a 5 Township by 5 Range grid model was used to determine the area of influence; subsequently, a smaller grid model 1 Township by 1 Range was used. Boundary producers were required to properly simulate an infinite aquifer. This study found that buoyancy and relative permeability, more than other parameters such as the perforation interval and the gas-water capillary pressure, affected the area of influence. A refined 75-layer model, one-metre thick, was constructed to check the gravity effect. The results of this refined layer model agree closely with a 13-layer model after 11 years of acid gas injection. A blowdown simulation was also conducted to determine the time to significant water inflow from perforations at the bottom of the zone. The effect of a 50 year shut-in after 30 years of injection was also simulated. Introduction The objective of the study was to understand the reservoir volume and the area of influence that would result from the injection of H2S into the Basal Sand aquifer of the Cambrian age Deadwood Formation. This was accomplished through the use of a compositional simulator (CMG's GEM). The Husky Lloydminster Upgrader (HLU) produces large amounts of acid gas: mainly H2S. The existing sulphur plant removes the sulphur from the H2S. Implementation of H2S disposal into the Deadwood Formation would initially reduce the load on the existing HLU sulphur plant, and ultimately it might be shut-in. Any future expansion of the HLU would not require an additional sulphur plant if acid gas disposal was proven to be effective. For safety reasons and regulatory requirements, it was required to know where the injected H2S would migrate to within the aquifer over time. The resulting area of influence would determine the penetrating wells and the mineral rights owners that might ultimately be affected by H2S injection. In this study, a commercial compositional simulator (CMG's GEM) was used as the model as it can take H2S water solubility into account. In the simulation results, the area of influence is defined as the area that has an H2S concentration greater than 0.00001 mole fraction. This value is based on the numerical accuracy of the simulation. The selected simulator was developed for oil-gas-water three-phase and multi-components usage. To simulate an H2S-water system, a small amount of methane (0.0005 gas saturation) was used as an oil phase for initialization. To distinguish the initial methane gas from H2S in the gas phase, all the gas saturation graphs used a minimum scale of 0.0005. Deadwood Aquifer Formation and Reservoir Model References (1) and (2) provide a detailed geological appraisal and a mineralogy study of the Cambrian Deadwood Formation Basal Sand.

Evaluation of the Potential for Gas and CO2 Leakage Along Wellbores

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 106817, "Evaluation of the Potential for Gas and CO2 Leakage Along Wellbores," by Theresa L. Watson, SPE, T.L. Watson & Assocs. Inc., and Stefan Bachu, Alberta Energy and Utilities Board, prepared for the 2007 SPE E&P Environmental and Safety Conference, Galveston, Texas, 5–7 March. Implementation of carbon dioxide (CO2) storage in geological media requires proper assessment of the risk of CO2 leakage from storage sites. Leakage pathways may exist through and along wellbores that penetrate or are near the storage site. One method of assessing the potential for CO2 leak-age is by mining databases that usually reside with regulatory agencies. Introduction CO2-injection schemes have been in operation since as early as the 1970s for tertiary oil recovery as miscible floods, with the indirect benefit of CO2 removal from the atmosphere. Other gas-injection schemes also are used in the oil and gas industry, such as natural-gas storage and acid-gas disposal. In the case of CO2 sequestration, the storage unit must be almost leak free to the atmosphere or other geological formations to meet safety requirements and greenhouse-gas-reduction objectives. The full-length paper focuses on human-created leak-age paths—in particular, abandoned wellbores that were drilled for oil and gas exploration and production. The analysis is based on data collected by the Alberta Energy and Utilities Board (EUB) for more than 315,000 wells drilled until the end of 2004 in the province of Alberta, Canada. EUB also records well leakage at the surface as surface-casing vent flow (SCVF) through wellbore annuli and gas migration (GM) outside casing. Background Abandonment Methods. Wells Drilled and Abandoned. For a typical openhole abandonment scenario in Alberta, regulations require that any porous zone be isolated or covered to prevent cross-flow between geological formations. In addition, useable groundwater must be covered with cement and isolated from potential hydrocarbon-bearing zones. After the downhole cement plugs have been set, the well must remain open for inspection for a minimum of 5 days. After this time, the well is checked for static fluid level or other indications of plug leakage before the casing can be cut and capped below grade level. Wells Drilled, Cased, Completed, and Abandoned. There are three main types of zonal isolation and abandonment for a typical cased-hole well after reservoir depletion.Bridge plug capped with cement above perforations.Retainer and cement squeezed into perforations.Cement plug set across perforations. Regulations since 2003 require zonal isolation behind casing and that useable groundwater be protected. In many cases, older wells were constructed with low annular cement tops, allowing many zones to be in communication behind casing. Under the current regulations, a cement squeeze would be required to achieve isolation before final abandonment. Wellbores must be abandoned with inhibited fluid inside the casing and be pressure tested to a minimum of 7000 kPa. Before cutting and capping the production and surface casing, the well must be checked for SCVF and

Acid Gas Sequestration During Tertiary Oil Recovery: Optimal Injection Strategies and Importance of Operational Parameters

Abstract This paper reports on an optimization study for acid gas injection into a fully depleted oil reservoir by numerical modeling. As a special case, the Zama Keg River Z3Z Oil Pool with one horizontal production well and previous acid gas disposal was considered. Acid gas generation (60 – 80% CO2 and 20 – 40% H2S) and safe geological disposal, or conversion to elemental sulphur with associated emissions, is an ongoing concern at Apache's Zama Gas Plant operations. The opportunity for a possible enhanced oil recovery application in the Zama field was foreseen given that use of CO2 in combination with H2S (acid gas) is known to reduce the minimum miscibility pressure with reservoir oils relative to using pure CO2 as a miscible agent. Storing H2S with the CO2 in underground reservoirs will double the benefit for the environment in terms of both short- (mainly H2S) and long-term (mainly CO2) effects to the environment. Ten (10) pinnacles were selected as potential candidates for a pilot project of acid gas injection (sequestration and EOR). Optimal conditions that maximize the oil recovery and the amount of acid gas sequestered were identified for one of these ten pinnacles-the Zama Keg River Z3Z Pool. Special attention was given to breakthrough times, incremental oil recovery and CO2/H2S sequestration volumes. After constructing the static reservoir model using the available data with stochastic/geostatistical techniques, history matching was performed. The compositional simulation option of a commercial simulator (ECLIPSE) was used for this purpose. Available PVT data were used and other data needed were generated using correlations. A number of different injection scenarios were then tested for the combination of optimum incremental oil recovery and acid gas sequestration. The following parameters were considered in the optimization study:miscibility;gravity override;cyclic injection;injection rate; and,injection and production well constraints (completion). Optimum injection strategies yielding maximum oil recovery and maximum acid gas storage, as well as delaying breakthrough time, were evaluated for these cases. Introduction The natural gas sweetening process produces sales gas and acid gas (CO2 and H2S) as a waste with a high percentage of CO2 in the Zama Field. The catalytic conversion of H2S into element sulphur, commercially called a Clause process, is a good economic process during times of high demand and high prices for sulphur. Reduction in world price of sulphur and the environmental hazard of stockpiling elemental sulphur in large blocks is a cause for concern in the oil and gas industry. Energy producers around the world are focusing on a value-added approach to enhanced oil recovery (EOR) or enhanced gas recovery (EGR) for greenhouse gas (GHG) disposal(1–4). Different injection strategies for CO2 injection, flue gas injection and Water Altering Gas (WAG) with CO2 have been studied and implemented for EOR since the 1970's(5–10). Acid gas was found to be an effective EOR agent since H2S reduces the minimum miscibility pressure (MMP) of CO2(11–13). By 2003, approximately 2.5 Mt CO2 and 2.0 Mt H2S have been stored in depleted oil/gas reservoirs or deep saline aquifers(14).

Modelling of Convective Mixing in CO2 Storage

Abstract Accurate modelling of the fate of injected CO2 is necessary if geological storage is to be used at a large scale. In one form of geological storage, CO2 is injected into an aquifer that has a sealing caprock, forming a CO2 cap beneath the caprock. The diffusion of CO2 into underlying formation waters increases the density of water near the top of the aquifer, bringing the system to a hydro-dynamically unstable state. Instabilities can arise from the combination of an unstable density profile and inherent perturbations within the system, e.g., formation heterogeneity. If created, this instability causes convective mixing and greatly accelerates the dissolution of CO2 into the aquifer. Accurate estimation of the rate of dissolution is important for risk assessments because the timescale for dissolution is the timescale over which the CO2 has a chance to leak through the caprock or any imperfectly sealed wells. A new 2D numerical model which has been developed to study the diffusive and convective mixing in geological storage of CO2 is described. Effects of different formation parameters are investigated in this paper. Results reveal that there are two different timescales involved. The first timescale is the time to onset the instability and the second one is the time to achieve ultimate dissolution. Depending on system Rayleigh number and the formation heterogeneity, convective mixing can greatly accelerate the dissolution of CO2 in an aquifer. Two field scale problems were studied. In the first, based on the Nisku aquifer, more than 60% of the ultimate dissolution was achieved after 800 years, while the computed timescale for dissolution in the same aquifer in the absence of convection was orders of magnitude larger. In the case of the Glauconitic sandstone aquifer, there was no convective instability. Results suggest that the presence and strength of convective instability should play an important role in choosing aquifers for CO2 storage. Introduction The use of technologies to capture and store CO2 is rapidly emerging as a potentially important tool for managing carbon emissions. Geological storage, defined as the process of injecting CO2 into geologic formations for the explicit purpose of avoiding atmospheric emission of CO2, is perhaps the most important nearterm option. Geological storage promises to reduce the cost of achieving deep reductions in CO2 emissions over the next few decades. While the technologies required to inject CO2 deep underground are well established in the upstream oil and gas sector, with such methods as CO2 -EOR(1,2) and Acid Gas disposal(3), methods for assessing and monitoring the long-term fate of CO2, and for assessing the risk of leakage, are in their infancy. Assessments of the risk of leakage of CO2 from a storage formation may need to analyze leakage mechanisms and their likelihood of occurrence during the full-time period over which mobile free-phase CO2 is expected to remain in the reservoir. Once dissolved, risk assessments may well ignore the leakage pathways resulting from the very slow movement of CO2 -saturated brines.

The Phase Behaviour of Acid Disposal Gases and the Potential Adverse Impact on Injection or Disposal Operations

Abstract As increased volumes of acid gases (containing carbon dioxide and hydrogen sulphide) are processed, the technique of downhole re-injection of the concentrated acid gas for disposal of these unwanted fluids continues to become more popular. In many cases, bottomhole injection temperature and pressure conditions are such that the injected acid gas phase is a supercritical fluid that is miscible with the existing reservoir fluids and, thus, the potential for adverse relative permeability effects (due to thecreation of in situ immiscible liquid and vapour phases) is avoided. In other cases, however, combinations of lower reservoir temperatures and/or initially depleted disposal zone pressures, or blending of the acid gas with the in situ lean gas, can result in the formation of both liquid and vapour acid gas phases in the formation in the near-wellbore region. This can often cause very significant relative permeability effects, which may result in large reductions in injectivity of the acid gas on either a permanent or transient basis. This paper provides actual examples of such systems, as well as reviewing the design protocol that must be used to evaluate if potential phase behaviour problems can occur downhole during an acid gas disposal operation. This hasproven to be a key parameter in the successful evaluation of anacid gas disposal operation. Introduction In many acid gas injection operations, the bottomhole pressure condition is high enough that, over the entire life of the injection operation and at all possible blended compositions between the acid injection gas and the reservoir fluids, a monophasic condition is present. In some cases, when the initial reservoir pressure is low, initial injection commences in the "gas" phase region, and as pressure gradually increases, the phase condition of the fluids around the injection wells enters the two-phase region where a "liquid" acid gas phase is in thermodynamic equilibrium with an acid gas "vapour" phase. This may also occur when the acid gas blends with reservoir gas which may elevate the dew point pressure line upwards above the current injection pressure level, once again resulting in a condition of two-phase flow. The creation of these two immiscible phases (which have an interface and measurable interfacial tension between them) can, particularly in lower permeability formations, create significant adverse relative permeability effects which may result in large transient or permanent reductions in injectivity, possibly compromising the economics of the acid gas injection operation. Understanding the phase behaviour in such situations and how it interacts with the capillary pressure and relative permeability phenomena present within the matrix of the proposed injection zone is essential. Limited data is available in the literature on the properties of high temperature and pressure acid gas mixtures and their specific phase behaviour(1–8). This is also the case with data regarding the specific interaction of single and multiphase acid gas interactions with reservoir rock(9–11) and the effects of multiphase acid gas induced relative permeability effects(12). The motivation of this work was to obtain a dataset to expand the knowledge base in this area.

Zama Acid Gas Disposal/Miscible Flood Implementation And Results

Abstract During 1994, Pennzoil Canada, Inc. entered into an agreement with Novagas Clearinghouse Ltd. (NCL) to re-inject the waste gas produced at their newly constructed Zama gas compression/ processing facility. Figure 1 highlights the project location. This paper will provide a general overview of the design, implementation, operation, and available results of this acid gas disposal/miscible flood project. Approval to inject 70 103m3/day waste gas was received from the EUB in March 1995. Injection limits were increased (August 1995) to 120 103m3/day which made the Zama acid gas system the largest in Canada. The acid gas (60% CO2 and 40% H2S) is being injected into the Zama Keg River "X2X" Pool (a previously waterflooded reef). Reinjecting the acid gas has several significant upsides. The immediate benefit is reduced atmospheric emissions. This one project is a significant contributor to CAPP's Climate Change Voluntary Challenge Committee. Additional benefits include tertiary crude oil reserves, subsurface sulphur storage and a more effective use of capital (i.e., compression versus sulphur recovery unit). The acid gas stream (based on theoretical and laboratory work) is miscible under achievable operating conditions. Unfortunately, the use of acid gas as a miscible product has not been widely published. Laboratory work has been required to refine our understanding of the process. The key results are included. Zama has not been an area where miscible flooding was considered an economic alternative (i.e., the reefs are relatively small and isolated). The construction of NCL's plant provided an inexpensive miscible solvent to test the process. The concept has broad applications to other reefs in the Zama area and elsewhere in Alberta. Introduction The oil industry as a whole is working towards a more responsible and proactive attitude towards the environmental issues. Pennzoil Canada, Inc. stepped forward to implement a very effective method of dealing with the waste gas produced at NCL's Zama facility (13-12-116-06W6M). The general benefits as outlined previously can be applied at many existing facilities and should be given consideration during the construction of new facilities. Potential miscibility was another key factor in Pennzoil's decision to participate in the acid gas disposal scheme. The Zama Basin contains a significant number of Keg River reefs with overlying Zama carbonates. Most of the larger pools were found during the early exploration phases and are now in various stages of depletion. Secondary recovery methods (waterflood, pressure maintenance) have met with mixed success. Tertiary recovery methods (gas injection, fireflood, etc.) have been attempted with no success reported to date. Pennzoil had considered miscible flooding as a potential recovery method in the Zama Basin (based on the process's application in the Rainbow Basin). Smaller reef size and miscible solvent availability made the option impractical. When NCL approached Pennzoil with the acid gas disposal concept, it was recognized as an opportunity to test the process and make available a long-term inexpensive, miscible solvent. The discussion will be organized into three general categories.Non-time specific informationThe pre-gas injection period (Data up to April 30, 1995)