Miscible Water-alternating-gas Research Articles

History Matching Under Geological Constraints Coupled with Multiobjective Optimization To Optimize MWAG Performance: A Case Study in a Giant Onshore Carbonate Reservoir in the Middle East

SummaryIn this paper we demonstrate how key geological uncertainties in a giant onshore carbonate reservoir in the Middle East, most notably fracture permeability and saturation distributions, impact the quality of the history match and change the performance forecasts of a planned miscible water alternating gas (MWAG) injection process.Different geological models for the reservoir were designed by integrating static and dynamic data. These data indicated the need to consider fault-related fractures using effective medium theory (EMT) and to update the saturation distribution by integrating special core analysis and log-derived J-functions in the reservoir model during the history matching. Afterward, multiobjective optimization (MOO) was applied for each history-matched model to identify well controls that optimally balanced the need to maximize the time on the plateau rate while adhering to the field's gas production constraints.Our results clearly show that including low-intensity fault-controlled fractures in the reservoir model improved the quality of the history match for the gas/oil ratio (GOR), BHP and water cut (WC). This is especially true for wells located near faults, which were difficult to match in the past. Moreover, our results further show that the updated saturation model improved the quality of the history match for the WC, and honored water saturation from the log with high accuracy, particularly for wells located in the transition zone.Applying MOO for each history-matched model then allowed us to identify well controls for the MWAG injection that could extend the time at which the reservoir would be produced at the plateau rate for up to 11 years and the risk of losing production plateau down to 2 years, while always adhering to the current field operational constraints.We demonstrate how the integration of MOO with an innovative workflow for fracture and saturation modeling impacts the prediction of a planned MWAG injection in a giant onshore carbonate reservoir. Our work clearly illustrates the potential of integrating MOO with new reservoir characterization methods to improve the quantification of uncertainties in reservoir performance predictions in carbonate reservoirs.

Experimental Program Investigates Miscible CO2 WAG Injection in Carbonate Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 188471, “Experimental Data Acquisition and Modeling for the Study of Miscible CO2 WAG in Carbonate Reservoirs Under Oil-Wet Conditions,” by T. Joubert, S. Duchenne, M. Bourgeois, SPE, R. de Loubens, SPE, and M. Petitfrere, Total, prepared for the 2017 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 13–16 November. The paper has not been peer reviewed. Prediction of miscible water-alternating-gas (WAG) injection performance relies on proper calibration of thermodynamical and petrophysical models. Swelling, miscibility, and stripping phenomena must be captured in the equation of state (EOS), and the oscillations of gas and water saturations require using history-dependent relative permeabilities. This paper provides a robust methodology for miscible CO2 WAG experimental-data acquisition and history matching. Introduction Miscible CO2 injection in oil reservoirs leads to low residual oil saturations in the swept areas. However, macroscopic sweeping can be poor because of the high mobility of CO2. One way of improving macroscopic sweep is to inject CO2 in the presence of mobile water to reduce its mobility (in tertiary or WAG modes). The prediction of WAG efficiency and the sizing of surface installations rely partly on the ability of the three-phase relative-permeability model to calculate proper mobility for each phase in any part of the reservoir. Numerous three-phase relative-permeability models have been proposed in the literature. Among these models, one proposed by Larsen and Skauge (1998) is considered by the authors as a starting point for simulation work. The experimental program discussed in this paper was launched in order to clarify several points, including the existence and the amplitude of residual oil saturation in miscible flooding and the validity of existing three-phase models. Experimental-Program Definition for WAG Study The experimental program is composed of several coreflooding experiments performed at reservoir conditions of 260 bar and 94°C. Materials and methods are discussed in detail in the complete paper. Flow Regions and Saturation Paths. WAG mechanisms involve alternating two fluids of different density and mobility properties at the injection well. These differences lead to gas migration toward the top of the reservoir. The consequence is a large variability of flow sequences in space as illustrated in Fig. 1, which shows a cross section between two vertical wells from a WAG phenomenological simulation. Several saturations paths were extracted to identify six flow regions that can be grouped into three categories: Two-phase flow with monotonous saturations variations (Flow Regions 1 and 2) Two-phase flow with oscillating saturations (Flow Regions 3 and 4) Three-phase flow with oscillating saturations (Flow Regions 5 and 6) Depending on reservoir properties and the development plan, the proportions between these flow regions can vary significantly and should be assessed for a given reservoir before the experimental-program definition. A reliable three-phase relative-permeability model should be valid over each flow region, or at least over the most significant one for a given case.

A State-of-the-Art Review To Develop Injection-Water-Chemistry Requirement Guidelines for IOR/EOR Projects

SummaryInjection-water chemistry plays a significant role in the impact of several improved-oil-recovery (IOR) and enhanced-oil-recovery (EOR) processes. Recently, advanced waterfloods through the tailoring of injection-water salinity and composition have received good attention in the oil industry for both sandstone and carbonate reservoirs. However, the importance of injection-water chemistry has not received its due attention as a whole in the IOR/EOR business because published studies in this area are distributed sparsely in bits and pieces without much relation to establish the strong connection. Also, injection-water-chemistry effects in certain EOR areas remain largely unexplored, even though they look somewhat promising. Moreover, the existing literature lacks a clear definition of injection-water-chemistry requirement guidelines for all IOR/EOR processes, including some of the newer processes that currently either are being practiced or are in research. In this paper, we provide a comprehensive review of more than 100 papers published during the past several decades in this subject area. The objectives of this review study are to provide an overview of smart-waterflooding technology; to describe important roles played by injection-water chemistry in the IOR/EOR business, with supporting examples; to extend the applicability of the smart-water concept to different IOR/EOR processes; and to develop the desired injection-water-chemistry requirement guidelines for IOR/EOR.The review analyses presented in this paper indicate that injection-water chemistry is important everywhere in the IOR/EOR business and is applicable not only to advanced waterfloods, but also to most of the recovery processes among the three major EOR types. These EOR processes include polymer flooding, alkaline-surfactant-polymer flooding, low-salinity surfactant flooding for sandstones, dilute-surfactant flooding for carbonates, carbonated waterflooding, miscible carbon dioxide (CO2) water-alternating-gas (WAG) flooding, and steamflooding. Injection waters of optimized salinity and ionic composition can also combine synergistically with several other EOR processes to result in higher incremental oil recoveries. Lower-salinity waters have a beneficial effect in polymer, surfactant, dilute-surfactant, and carbonated waterfloods, to yield better oil recoveries when compared with high-salinity water. The use of smart water for tertiary miscible CO2 WAG floods and carbonated waterflooding appears promising; however, it requires additional research to clearly distinguish and determine smart-water effects in these processes. The review analyses are finally extended to develop the desired injection-water-chemistry requirements for all individual IOR/EOR processes currently known. The findings of this study also put forward two major recommendations for consideration by the industry: (1) there is a need for close collaboration between water and oil industries to develop fit-for-purpose water-treatment solutions for addressing IOR/EOR injection-water-chemistry requirements, and (2) some thought should be given to develop “water chemistry” as a specialty discipline within the oil industry, for better integration of this emerging focus area with other key surface- and subsurface-related disciplines to effectively improve upon the IOR/EOR upstream value chain.

Technology Focus: EOR Performance and Modeling (January 2015)

Technology Focus We can easily state that incorporating enhanced-recovery focus into field- management practices as early as possible is finally becoming the norm. No longer is enhanced oil recovery (EOR) something operators procrastinate about and not act on until the end of the life of a field. Growing recovery challenges of maturing fields definitely are one of the reasons for this historical change in focus. We should also acknowledge the effect of growing unconventional oil operations and, more importantly, their severe recovery challenges. Increasing recovery factors in tight, light reservoirs is one of the more prominent research topics in the oil industry in recent years. Last but not least, EOR is being implemented in offshore operations. This new paradigm—caring for production and recovery, optimizing production rates and recovery factors simultaneously—is being realized with significant help from new technologies. Significant enhancements in reservoir characterization, EOR chemicals, modeling capabilities (EOR software and computational power), conformance capabilities, and monitoring and control systems, along with improved understanding of flow physics, are making EOR easier for our industry. Ongoing EOR research is bringing complex EOR schemes to the industry; some of the examples are low-salinity CO2 water-alternating-gas (WAG) injection, CO2/steam injection, steam/ solvent injection, and microbial EOR. Integration for successful EOR projects is also maturing. Historically, with steam-assisted gravity drainage, we all recognized the effect of well trajectory on recovery. More recently, we have identified the relationship between massive fracture architecture and EOR in tight, light reservoirs. It is worth mentioning that unconventionals have been pushing reservoir characterization, drilling, and completions to yet another level. All that effort not only improves the performance of those special reservoirs but also makes EOR easier for conventionals. As a result of the focus on enhancing recovery for all types of reservoirs, many great technical papers were available for this feature this year. The following pages will provide some insights into how EOR is being tested for tight, light reservoirs; into low-salinity CO2 WAG experimentation; and into giant-field EOR applications. More papers can be found in the OnePetro online library, including those listed for recommended additional reading. JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE 169076 Modeling of Viscous Displacement in Dual-Porosity Naturally Fractured Reservoirs: Application to Surfactant Enhanced Oil Recovery by Mojtaba Kiani, Tiorco, et al. SPE 169170 Assessment of Three-Phase Relative Permeability and Hysteresis Models for Simulation of Water- Alternating-Gas Injection in Water- Wet and Mixed-Wet Systems by Omid Shahrokhi, Heriot-Watt University, et al. SPE 169102 Low-Salinity Waterflooding at West Salym: Laboratory Experiments and Field Forecasts by B.M.J.M. Suijkerbuijk, Shell, et al. OTC 24483 Relative Permeability Effects on the Miscible CO2 WAG Injection Schemes Through Compositional Simulations of Brazilian Small-Scale Water-Wet Synthetic Presalt Reservoir by S.F. Mello, Universidade Estadual de Campinas, et al.

Performance assessment of miscible and immiscible water-alternating gas floods with simple tools

Abstract Water-alternating-gas (WAG) floods are designed to lessen the mobility of CO2 and thereby increase sweep efficiency. Common factors that often lead to less-than-ideal flood performance include reservoir heterogeneity triggering nonintuitive injector/producer connectivity, lack of conformance control, and injection at pressure greater than the fracture pressure, among others. Therefore, intensive reservoir monitoring and data interpretation should be the cornerstone of any prudent reservoir-management practice. This study uses a slate of analytical tools to monitor flood performance in miscible and immiscible WAG floods. These tools include the capacitance-resistance model (CRM) and several diagnostic plots, such as the reciprocal-productivity index (RPI), the water–oil ratio (WOR), EOR-efficiency-measure plot, and modified Hall plot (MH). This paper offers several alternative CRM solutions to account for unbalanced patterns.

Three-Phase Relative Permeability Modeling in the Simulation of WAG Injection

Summary We propose a new workflow to evaluate the effect of three-phase relative permeability models on the simulation of water-alternating-gas (WAG) injection: define a root-mean-square error to quantify differences between the models; introduce a high-uncertainty region on a ternary saturation diagram; and map simulation saturation/time paths in this ternary diagram. The display of the saturation paths, along with the high-uncertainty region, allows us to systematically analyze and understand the effect of three-phase models on recovery predictions. We apply the workflow to immiscible and miscible WAG injection, simulated by use of black-oil and compositional models. Both 2D homogeneous cases (with various reservoir conditions and injection scheduling) and realistic 3D field sector models are considered. We show that the three-phase relative permeability models can have a strong effect on recovery predictions for immiscible WAG injection, and the effect depends on initial conditions and displacement history. For compositional simulation of multicontact miscible WAG injection, the effect of three-phase models depends on the size of the three-phase-flow region before the miscibility fully develops. Simulation of carbon dioxide (CO2) flooding on a 3D field sector model reveals that the uncertainty in recovery predictions because of the various three-phase models is secondary compared with other sources of uncertainty (such as the input two-phase relative permeability data), and this may be the case in other field studies.

Analytical Model for Zones Distributions in Non-Horizontal Miscible WAG Injection

The advantages of WAG (water-alternating-gas) injection compared to gas injection and waterflooding, from technical and economical points of view, are results of creating a mixed zone in which both water and gas are flowing simultaneously. Previously, an analytical model was developed in the literature to evaluate complete segregation distance and zone distributions for horizontal miscible WAG injection models. Even though this analytical model is derived using simplifying assumptions, it still gives good insight into the design of new projects when the lack of data does not allow a detailed full field reservoir simulation to be carried out. On the other hand, the advantages and disadvantages of applying WAG injection in dipped reservoirs, and up-dip or down-dip patterns are still in question while there isn’t any analytical model available for analyzing process in this type of reservoir. This paper develops analytical equations for a non-horizontal model and investigates the effect of dip angle on segregation effects in miscible WAG injection process. Up-dip versus down-dip WAG injection is another subject which will be discussed in this paper.

Experimental Investigation of Miscible CO2 Flooding

Management of water alternating gas (WAG) injection projects requires making decisions regarding the WAG ratio, half-cycle-slug size, and ultimate solvent slug size. The impact of these decisions affects the capital cost and ultimate incremental oil recovery. Core flooding runs were conducted on 2 and 4 ft core samples. Injection scheme (continuous gas injection [CGI] vs. WAG), WAG ratio, and slug size were investigated. In addition, miscible WAG flooding as a secondary process was investigated and its efficiency was compared to the conventional tertiary miscible gas flooding. Miscible gas flooding at different miscible WAG parameters (WAG ratio and slug size) indicate that 1:2 WAG ratio at 0.2 PV slug size is the best combination yielding the highest recovery and tertiary recovery factors. Miscible WAG flooding as a secondary process indicated a higher ultimate recovery compared to the conventional tertiary WAG flooding. However, a larger amount of gas injection is consumed particularly in the early stages of the injection process. Miscible CGI mode conducted using n-Decane as oleic phase appears to have better performance than miscible WAG injection in term of recovery. When light Arab crude oil was used as oleic phase, higher recovery was obtained for miscible WAG flooding. The reversal trend seen in is believed to be due to the presence of crude oil, which alters the rock wettability toward an oil-wet condition, preventing the water blockage during the WAG process.

Systematic Surveillance Techniques for a Large Miscible WAG Flood

Summary Miscible water-alternating-gas (WAG) flooding has proven to be an attractive enhanced-oil-recovery (EOR) method the world over. Successful WAG floods can yield significant additional oil recovery over waterflooding. WAG floods are complex in nature since reduction of residual oil in the pore spaces depends on mass transfer. Optimizing miscibile contact between the injected gas and the reservoir oil over a large rock volume is challenging. This challenge is more manageable in a small-scale pilot flood or a coreflood than in a large field implementation. Numerical-simulation efforts can provide guidance to designing an optimal flood. However, the field application will often reveal challenges that are not discovered in the pilot stage or by the full-field simulation model because the geologic properties and heterogeneity of the reservoir rock are not accurately represented. Integrated surveillance of a WAG flood is the only means to determine whether the flood is working efficiently and the planned additional recovery will be delivered. A well-implemented surveillance plan allows timely intervention to improve the efficiency of an underperforming WAG flood. This paper presents a systematic approach for applying EOR surveillance tools and methods in large miscible WAG floods in the Ivishak reservoirs at the Prudhoe Bay and Eileen West End (EWE) of the North Slope, Alaska. Highlights of these surveillance methods are (1) designed and implemented by a multidisciplinary team, (2) based on proven theory and corroborated with field data, (3) requires easily obtainable and relatively inexpensive field data and analysis, and (4) applied from fault block down to zone levels. Implementation of these tools has helped to identify the efficiency of flood patterns and areas of poor performance, which then can be modified through infill drilling, well recompletion, or WAG-ratio modification to maximize EOR recovery.

Analytical and numerical investigation of multicomponent multiphase WAG displacements

In this paper the ability of analytical solutions for four-component three-phase flow to predict displacement efficiency in water alternating gas (WAG) injection processes is studied. First analytical solutions for Riemann problems with injection compositions that are the average water and gas mixture for various WAG injection schemes are presented. These solutions are compared to numerical calculations with variable slug sizes and used to explore the effect of slug size, injecting water vs gas first, and the average injection composition on displacement efficiency in compositional WAG schemes. The example model is partially miscible WAG injection of water and CO2 into an oil reservoir containing C10 and CH4 with and without a mobile aqueous phase present initially. The trailing end of the water and gas profiles are sensitive to whether water or gas is injected first, but the magnitude of the oil bank and the breakthrough time of the injected fluids are accurately predicted by the analytical solutions, even for displacements where large water and gas slugs are injected. Fluctuations in the saturation and composition profiles resulting from the alternating injection sequence in the WAG simulations appear as super-imposed on top of the sequence of rarefaction and shock waves predicted by analytical solutions. As the number of slugs increases, the effect of alternating boundary conditions diminishes and the displacements predicted by numerical calculations converge to the analytical solutions.

Slug Water Alternating Gas Flow Processes Behavior in the Vicinity of Discontinuous Shales

Gas injection is the second largest enhanced oil recovery process practiced in the world. To increase the macroscopic sweep efficiency, the gas is generally injected intermittently with water either simultaneously or as slugs. This mode of injection, called water alternating gas (WAG), is being widely used in the oil fields. This experimental and numerical study is aimed at understanding mechanisms of oil recovery following slug first-contact miscible WAG (FCMWAG) injection in the presence of discontinuous shales. A particular objective is to quantify the accuracy of numerical simulation when modeling slug FCMWAG displacements in these heterogeneous systems. A series of well-characterized laboratory experiments in two-dimensional heterogeneous bead packs were carried out. Slug FCMWAG displacement experiments were performed in the porous media containing discontinuous shale. Slug injection was carried out at a WAG ratio of 1:1 with slug sizes of 5 and 50% PV. All experiments were then modeled using IMPES finite difference simulator without using history matching (all simulations used directly measured porous media properties as inputs) to quantify the accuracy of the simulation when modeling the slug FCMWAG displacements in a porous media with a discontinuous shale. The large water slug (50% PV) displacement outperformed the 5% PV slug process because the large water slug injected ahead of solvent significantly reduced the extent of fingering and the bypassed oil around the shale barrier. Simulation of the slug WAG experiments showed good agreement for the oil recovery. However, a discrepancy in the physics of the fluid flow during the displacements, especially downstream and upstream of the shale barrier, was observed in the fluid cut curves. Simulation predicted less fingering and fewer breakdowns of the injected slugs.

The Areal Sweep Efficiency of the First-contact Miscible Displacements: An Experimental Approach

Solvent flooding using the water alternating gas (WAG) technique is very important for predicting the process performance. This technique has been employed in a number of oil fields. However, little data are available in the literature. Therefore, there is an immense need for the sweep efficiency data resulting from first-contact miscible flooding, particularly in view of conducting reservoir simulation studies. In this article, we conducted a series of WAG displacements through glass bead packs. A number of miscible WAG displacement tests were conducted at WAG ratios of 1:1, 1:2, and 2:1. Constant flow rates were used to mask the effects of capillary number on sweep efficiency. Experimental results revealed that the WAG ratio affects the sweep efficiency of the miscible flooding process. In addition, new correlations of areal sweep as function of mobility ratio at various WAG ratios were developed. The data provided can be useful to the oil industry in conducting analytical and numerical modeling studies of miscible WAG processes.

A Survey of North Sea Enhanced-Oil-Recovery Projects Initiated During the Years 1975 to 2005

Summary This paper provides a summary and a guide of the enhanced-oil-recovery (EOR) technologies initiated in the North Sea in the period from 1975 until beginning of 2005. The five EOR technologies that have been initiated in this region are hydrocarbon (HC) miscible gas injection, water-alternating-gas (WAG) injection injection, simultaneous water-and-gas (SWAG) injection, foam-assisted WAG (FAWAG) injection, and microbial EOR (MEOR). Each EOR technology that has been initiated in the North Sea was identified with its respective maturity level and/or maturation time frame, technology use restrictions, and process efficiency on the basis of incremental oil. Apart from WAG at Ekofisk and FAWAG at Snorre central fault block (CFB), all technologies have been applied successfully (i.e., positive in economic terms) to the associated fields. HC miscible gas injection and WAG injection can be considered mature technologies in the North Sea. The most commonly used EOR technology in the North Sea has been WAG, and it is recognized as the most successful EOR technology. The main problems experienced were injectivity (WAG, SWAG, and FAWAG projects), injection system monitoring, and reservoir heterogeneities (HC miscible gas injection, WAG, SWAG, and FAWAG projects). Approximately 63% of all the reported EOR field applications have been initiated on the Norwegian continental shelf (NCS), 32% on the UK continental shelf, and the remainder on the Danish continental shelf. Statoil has been the leader in conducting EOR field applications in the North Sea. The majority of future research will concentrate on microbial processes, CO2 injection, and WAG (including SWAG) injection schemes. In this review, laboratory techniques, global statistics, simulation tools, and economical evaluation were not considered and are considered outside of the scope of this paper.

A New Approach to Forecasting Miscible Water Alternating Gas Performance at the Field Scale

Summary Full-field enhanced oil recovery (EOR) performance predictions are generally obtained from scale-up tools, because three-dimensional (3D) finite-difference simulations would be too CPU-inten- sive. Existing scale-up techniques require the user to define pattern elements and then to derive performance curves to apply to each injector-producer pair in the elements. Accurate assignment of these elements is difficult because the actual shape and size of the swept volumes are sensitive to reservoir faulting, well-rate changes, and regional flux. In reality, the actual sweep region is not an input parameter, but should be determined by the regional pressure field, which changes as well rates vary and new wells are drilled. Thus, a major source of error in using existing scale-up tools is trying to define representative pattern elements. In the current paper, we describe a scale-up technique in which the user does not have to define pattern elements or injector-producer pairs. In the new technique, the pressure field is computed at each timestep and then a front-tracking algorithm propagates water and miscible injectant throughout the reservoir. The miscible-gas process is modeled by means of an analogy between oil mobilization and adsorption/ desorption of tracers. The parameters for the model are obtained by fine-scale, two-dimensional (2D), compositional, finite-difference simulations in a vertical cross section. In the new approach, the injected solvent is divided into an effective and an ineffective portion. This approach reduces a 3D problem to a 2D, areal one in which the declining displacement efficiency of the solvent, which is caused by vertical effects, is captured by decreasing the injected concentration of effective solvent with time. In this paper, we show how the new scale-up tool has been used to model the miscible water-alternating-gas (MWAG) process in the Eastern Peripheral Wedge zone (EPWZ) of the Prudhoe Bay field. We show a comparison between field response and model predictions.

Kuparuk Large-Scale Enhanced Oil Recovery Project

Summary The Kuparuk River oil field has had a "miscible" water-alternating-gas (MWAG) enhanced-oil-recovery (EOR) pilot in place since 1988. This original pilot was implemented on two drillsites previously on waterflood. The pilot was expanded to a third drillsite in 1993 to test the MWAG process in an area previously flooded by an "immiscible" water-alternating-gas (IWAG) recovery technique. Large-scale application of MWAG at Kuparuk is in progress, with a project that will more than triple current MWAG injection. Full implementation is slated for mid-1996. When completed, the Kuparuk large-scale EOR (LSEOR) project will be among the largest of its kind in the world. This paper covers the basic aspects of moving the EOR process at Kuparuk from pilot to large-scale application. A number of hurdles had to be overcome, including scaleup of field and simulation results in a consistent manner and the need to use existing infrastructure to ensure economic viability

Performance evaluation and optimization of the Kuparuk hydrocarbon miscible water-alternating-gas flood

Abstract In 1988 a hydrocarbon miscible water-alternating-gas (MWAG) pilot was initiated in the Kuparuk River field, on the North Slope of Alaska. Project decline curve analysis showed a significant response to the MWAG process. The field data alone, however, could not be used to accurately project the ultimate performance of the process. A systematic, integrated approach to reservoir modelling was used to evaluate the MWAG process performance. Finely gridded one dimensional (1D) models were used to evaluate the process mechanisms. Then fine and coarsely layered 2D and 3D compositional models were used to evaluate the process efficiency. The areal effects, including faulting, were then incorporated by using a 3D, coarsely gridded, multi-well, modified black oil (MBO) model. The 3D, site-specific, model was history-matched for the waterflooding period. The miscible flood performance was then predicted using a tuned MBO parameter and compared to the field performance. The 3D MBO model predicted that the ultimate incremental recovery would be 11 0.000000or a 30% HCPV slug. The model indicated that the miscible process can accelerate production of the waterflood reserves. The model was also used to evaluate the effects of total slug size, maturity of the preceding waterflood, and WAG ratio on the process efficiency.

A Field Test of Nitrogen WAG Injectivity

Summary A one-well field test of nitrogen WAG (water alternating gas) injectivity was conducted to determine whether a reduction in water injectivity would occur after injection of nitrogen. A 40% reduction was observed immediately after nitrogen injection. Following three short WAG cycles, water injectivity increased to its pretest level with injection of a large volume of water. Introduction The Jay/LEC field in Florida and Alabama is producing under unitized waterflood operations. Several papers describe this field's historical development. The field test described in this paper was undertaken as part of an engineering evaluation of injecting nitrogen and water alternately into the Jay/LEC field Smackover reservoir to determine the effect on a miscible gas tertiary process. Several operators of miscible WAG injection projects have encountered a reduction in water injectivity after gas injection. in two projects, water injectivity decreased significantly and operators speculated that either the precipitation of asphaltenes, trapped residual gas saturation, or movement of fine granules of reservoir rock caused declines in injectivity. These projects were unable to achieve oil production rates forecast because more than the anticipated time was required to inject planned water volumes. If a reduction in water injectivity occurs because of trapped carbon dioxide saturation, the high solubility of carbon dioxide in water should allow water injectivity to increase rapidly during the succeeding water injection cycle. In addition, injection wells may experience a slight increase in permeability and porosity due to the solution of carbon dioxide in water forming a weak acid. In a nitrogen WAG project, the low solubility of nitrogen in water will prevent the trapped gas saturation from changing significantly during the water injection phases of WAG injection. Several documented WAG projects using low-water-soluble gases have observed significant reductions in water injectivity, while significant reductions in water injectivity when high-water-soluble gases are used are not documented. Laboratory experiments were performed with cores from the Jay/LEC field in an attempt to determine whether a seduction in water injectivity would occur if nitrogen and water were injected alternately into the Smackover reservoir. The results of these experiments were inconsistent. Changing rock wettability and movement of formation fines may have contributed to the inconsistent results. Since laboratory experiments to provide a basis for predicting field injectivity were unsuccessful, and in light of reported poor field performance, a field test was carried out to determine whether nitrogen WAG injection into the Jay/LEC Smackover reservoir would reduce water injectivity. During the field test initiated in Aug. 1978, reservoir injectivities and transmissibilities of water and nitrogen were observed during three cycles of nitrogen followed by water injection into a Jay/LEC field well. The conventional Homer analysis interpretation technique did not provide definitive solutions. A technique consisting of plotting transmissibility vs. square root of shut-in time provided a useful tool for observing fluid banks in the reservoir and evaluating changes in water and gas injectivities. Design To ensure the selection of a representative injection well and simplify interpretation of bottom hole pressure measurements, the following criteria were established.Reservoir development in the injection well should be limited to one relatively thin zone.The ratio of permeability-thickness to injection rates during the injectivity test should be representative of rates in injection wells if a field wide project is carried out JPT P. 266^