Reduction Of Water Production Research Articles

Effects of Different Irrigation Levels and Fertilizer Rates on Yield, Yield Components and Water Productivity of Onion at Adami Tulu Agricultural Research Center

Today’s agriculture sector faces a complex series of challenges to cope with the demands for sustainable management and production, which entails an increase in food production to ensure food security while using less water per unit of output and reducing nitrogen (N) fertilizer losses through leaching. The experiment was conducted at Adami Tulu Agricultural Research Center on-station to study the effect of different irrigation levels and N-fertilizer rates on plant height, bulb yield, bulb diameter, and bulb height and water productivity of onion. The treatments of the experiment had factorial combinations of three levels of watering and four N-fertilizer amounts. Results indicated that the highest plant height (53.07 cm), bulb height (6.13 cm), bulb diameter (6.21 cm), marketable bulb yield (241.39 qt/ha) and total bulb yield (252.89 qt/ha) were obtained from full irrigation and fully N-fertilized compared to the deficit conditions. The highest water productivity was recorded from 60% ETc irrigation level and 150 Kg/ha N-fertilizer application rate, but the reduction in water productivity with 80% ETc and 150 Kg/ha N-fertilizer application rate was not significant. Hence, if water is not limiting factor, 100% ETc irrigation level and 150 Kg/ha N-fertilizer could be suggested to apply. But if water becomes 232 limiting factor, 80% ETc irrigation level with 150 Kg/ha N-fertilizer would be more appropriate for growing onion in the study area. Therefore these can be used as one package of onion production technology and all growers better to apply.

Development of an analytical model to predict oil reservoirs performance using mechanical waves propagation

The mechanical waves have been used as an unconventional enhanced oil recovery technique. It has been tested in many laboratory experiments as well as several field trials. This paper presents a robust forecasting model that can be used as an effective tool to predict the reservoir performance while applying seismic EOR technique. This model is developed by extending the wave induced fluid flow theory to account for the change in the reservoir characteristics as a result of wave application. A MATLAB program was developed based on the modified theory. The wave’s intensity, pressure, and energy dissipation spatial distributions are calculated. The portion of energy converted into thermal energy in the reservoir is assessed. The changes in reservoir properties due to temperature and pressure changes are considered. The incremental oil recovery and reduction in water production as a result of wave application are then calculated. The developed model was validated against actual performance of Liaohe oil field. The model results show that the wave application increases oil production from 33 to 47 ton/day and decreases water-oil ratio from 68 to 48%, which is close to the field measurements. A parametric analysis is performed to identify the important parameters that affect reservoir performance under seismic EOR. In addition, the study determines the optimum ranges of reservoir properties where this technique is most beneficial.

Water productivity of two wheat genotypes in response to no-tillage in the North China Plain

Uneven distribution of precipitation and overexploitation of groundwater resources threatens the sustainability of agriculture in the North China Plain. Adoption of water deficit-tolerant winter wheat genotypes coupled with timely, adequate farming practice is crucial to enhance sustainable crop production and water productivity in the region. The present study aimed to evaluate water consumption patterns and water productivity of two winter wheat genotypes (Tainong-18 and Jimai-22), under no-tillage or conventional tillage, over a period of four consecutive cropping seasons. Under no-tillage, Tainong-18 showed the lowest soil moisture consumption before sowing in the 30–110 cm soil profile. Jimai-22 under conventional tillage and Tainong-18 under no-tillage showed the highest and lowest evapotranspiration across cropping seasons, respectively. Compared with conventional tillage, no-tillage reduced grain yield and water productivity of winter wheat, and the difference between them increased for grain yield (6.79, 11.99, 14.78, and 15.73%) and water productivity (0.99, 8.14, 12.18, and 13.30%) over the 2015–2016, 2016–2017, 2017–2018, and 2018–2019 cropping seasons, respectively. In contrast, Tainong-18 showed lower evapotranspiration and increased grain yield and water productivity compared with Jimai-22. Further, Tainong-18 showed a compensatory effect on the reduction of water productivity under no-tillage, compared with Jimai-22. Our conclusions indicate that the combination of no-tillage and water-efficient winter wheat genotypes is an effective strategy to offset the reduction in water productivity caused by no-tillage and thus maximise water productivity in the North China Plain.

Evaluation of the Effectiveness of Continuous Gas Displacement for EOR in Hydraulically Fractured Shale Reservoirs

SummaryThe main objective of this study is to analyze and describe quantitatively the effectiveness of continuous gas displacement as an enhanced oil recovery (EOR) process to increase production from multifractured shale oil reservoirs. The study uses CH4 continuously injected through horizontal wells parallel to the production wells as the displacement agent and investigates the effects of various attributes of the matrix and of the induced and natural fracture systems.This numerical simulation study focuses on the analysis of the 3D minimum repeatable element (stencil/domain) that can describe a hydraulically fractured shale reservoir under production. The stencil is discretized using a very fine (millimeter-scale) grid. We compare the solutions to a reference case that involves simple depressurization-induced production (i.e., without a gas drive). We monitor continuously (a) the rate and composition of the production stream and (b) the spatial distributions of pressure, temperature, phase saturations, and relative permeabilities.The results of the study indicate that a continuous CH4-based displacement that begins at the onset of production does not appear to be an effective EOR method for hydraulically fractured shale oil reservoirs over a 5-year period in reservoirs in which natural or induced fractures in the undisturbed reservoir and/or in the stimulated reservoir volume (SRV) can be adequately described by a single-medium porosity and permeability. Under these conditions in a system with typical Bakken or Eagle Ford matrix and fracture attributes, continuous CH4 injection by means of a horizontal well parallel to the production well causes a reduction in water production and an (expected) increase in gas production but does not lead to any significant increase in oil production. This is attributed to (a) the limited penetration of the injected gas into the ultralow-k formation, (b) the dissolution of the injected gas into the oil, and (c) its early arrival at the hydraulic fracture (HF; thus, short circuiting the EOR process by bypassing the bulk of the matrix), in addition to (d) the increase in the pressure of the HF and the consequent reduction in the driving force of production and the resulting flow. Under the conditions of this study, these observations hold true for domains with and without an SRV over a wide range of matrix permeabilities and for different lengths and positions (relative to the HF) of the gas injection wells.

Investigation of the influence of the carbon dioxide (CO2) injection rate on the activity of the water pressure system during gas condensate fields development

The development of gas condensate fields under the conditions of elastic water drive is characterized by uneven movement of the gas-water. Factors of hydrocarbon recovery from producing reservoirs which are characterized by the active water pressure drive on the average make up 50-60%. To increase the efficiency of fields development, which are characterized by an elastic water drive, a study of the effect of different volumes of carbon dioxide injection at the gas-water contact on the activity of the water pressure system and the process of flooding producing wells was carried out. Using a three-dimensional model, the injection of carbon dioxide into wells located at the boundary of gas-water contact with flow rates from 20 to 500 thousand m3/day was investigated. Analyzing the simulation data, it was found that increasing the volume of carbon dioxide injection provides an increase in accumulated gas production and a significant reduction in water production. The main effect of the introduction of this technology is achieved by increasing the rate of carbon dioxide injection to 300 thousand m3/day. The set injection rates allowed us to increase gas production by 67% and reduce water production by 83.9% compared to the corresponding indicators without injection of carbon dioxide. Taking into account above- mentioned, the final decision on the introduction of carbon dioxide injection technology and optimal technological parameters of producing and injection wells operation should be made on the basis of a comprehensive technical and economic analysis using modern methods of the hydrodynamic modeling of reservoir systems.

Polyindole nanoparticle-based electrorheological fluid and its green and clean future potential conformance control technique to oil fields

The remaining challenging issue during oil production from reservoir is reduction of water production using a conformance control technique. As a new method, the feasibility of an electrorheological (ER) suspension for forming a solid-like structure to obstruct the pore throat in porous media was investigated. Suitable conducting nanoparticles for injection into an oil reservoir with regard to size, morphological shape, and field scale capability were synthesized and characterized, then dispersed in two types of oil: heavy and light crude oil. A series of ER experiments, including steady shear and dynamic tests were performed to determine the ability of the proposed conformance control fluid to produce a solid-like form with the electric field. The fluid was then modeled using both the Bingham and Herschel-Bulkley equations. The large ER behaviors proved feasibility of the proposed conformance controlling fluid for reducing water production, which can make the oil production operation more economical and environmentally friendly.

Gas-Lifting Characteristics of Methane-Water Mixture and Its Potential Application for Self-Eruption Production of Marine Natural Gas Hydrates

A gas-lifting production method was firstly proposed to transport the methane-water mixture from natural gas hydrates deposits through marine vertical pipe in this work. Aiming at UBGH2-6 site, SH7 site and GMGS2-8 site, the gas-lifting performance of methane-water mixture in the vertical pipe was investigated by numerical calculation. The potential of Natural gas hydrates (NGH) self-eruption production induced by the gas-lifting process under ideal conditions was also studied based on the energy analysis. The calculation results indicate that the gas-lifting method has great advantage in avoiding the secondary hydrates formation in marine vertical pipe and reducing energy consumption. The gas-lifting process in the vertical pipe is testified to be spontaneous in UBGH2-6 site and SH7 site during the initial 4000 and 1000 days, respectively, which indicates the energy consumption for methane-water mixture transportation is saved. Sufficient heat supply for the hydrate dissociation is crucial for the NGH self-eruption production. Sensitivity analysis indicates that the water-gas ratio has more significant influences on gas-lifting performance in the vertical pipe compared to the flow rate. With the decrease of water-gas ratio, the bottomhole pressure decreases rapidly. Thus, the reduction of water production is effective to improve the gas-lifting performance.

Colloidal-Dispersion Gel in a Heterogeneous Reservoir in Argentina

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 174704, “CDG in a Heterogeneous Fluvial Reservoir in Argentina: Pilot and Field-Expansion Evaluation,” by D. Diaz and N. Saez, YPF; M. Cabrera, InLab; E. Manrique, Consultant; and J. Romero, M. Kazempour, and N. Aye, Tiorco, prepared for the 2015 SPE Enhanced Oil Recovery Conference, Kuala Lumpur, 11–13 August. The paper has not been peer reviewed. The Loma Alta Sur (LAS) field is a multilayer fluvial sandstone reservoir in the Neuquén basin of Argentina. Reservoir heterogeneities and an adverse mobility ratio (30-cp oil) led to an early water breakthrough soon after water injection started. Colloidal-dispersion- gel (CDG) injection was considered a viable strategy to improve oil recovery in the field. LAS-58 CDG Pilot Summary The CDG pilot was implemented in the LAS-58 injector located on the northeastern side of the field. LAS-58 is an irregular pattern that began water injection in 2002, showing an early water breakthrough. The operator estimates that after 3 years of water injection in the LAS-58 pattern, cumulative secondary oil recovery is only 5.48% of original oil in place (OOIP). The LAS-58 pattern includes 10 producers: six first-line producers with well spacing ranging from 138 to 164 m and four second-line producers. The first tracer-injection program was implemented in March of 2003, 3 months after initial water injection in the LAS-58 injector. The fastest tracer breakthrough was observed in offset producer LAS-18 (50 days). However, the amount of tracer recovered in LAS-18 and LAS-26 was below 1.5% of the total injected. Producer LAS-49 showed the second-fastest breakthrough but with a cumulative tracer recovery of 4%. Each of the CDG-injection phases was followed by water injection at similar injection rates. The total volume of CDG injected (62 179 m3) represented 3.06% of the pore volume of the LAS-58 pilot area. Phase I consisted of a small injection volume intended to test CDG injectivity and did not affect pilot oil-production response but definitively contributed to adjusting the polymer concentration used in the pilot through Phases II and III of CDG injection. The main observation after Phase II of CDG injection was a very distinctive change in the injection profile of the LAS-58 injector. The water-injection flow paths were diverted into the middle (Mandrel 2) and bottom (Mandrel 1) zones of the pay zone because of the reduction in injectivity in the thief zones located at the top (Mandrel 3) of the reservoir. In October 2007, the incremental oil production for the 10 offset producers was reported as 133,292 bbl, with a reduction in water production of 406,949 bbl.

Application of simulated annealing optimization algorithm to optimal operation of intelligent well completions in an offshore oil reservoir

The latest intelligent fields include intelligent well completions capable of collecting downhole data, which allow the operator to selectively control completion intervals throughout the life of a reservoir. Performance can be monitored and optimized in real time and operations can be adjusted remotely using downhole equipment. To quantify and develop this potential, we deigned an algorithm-based system which is capable of optimizing intelligent well control to decide on whether or not to utilize intelligent well technology. Simulated annealing algorithm was used for obtaining an optimum control strategy and determining an operation that maximizes the net present value (NPV). In this article, we used more than 4,000 simulation runs which were performed automatically in a reservoir simulator to optimize a cyclic production scenario with intelligent well completions. The intelligent wells were equipped with on/off inflow control valves in each zone, which were opened and closed sequentially to maximize the oil rate while not exceeding limits for water production. The results show that the application of simulated annealing algorithm for optimization of intelligent well technology culminates in an increase in the NPV through 14 % increase in cumulative oil production and a significant reduction in water production.

Cyclic-Production-Scheme Performance Evaluated Using Reservoir Simulation

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164168, ’Appraising the Performance of a Cyclic-Production Scheme Through Reservoir Simulation: A Case Study,’ by Tariq Al-Zahrani, Saudi Aramco, prepared for the 2013 SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 10-13 March. The paper has not been peer reviewed. Many strategies have been implemented to mitigate the problem of high water-production rates seen in mature fields. One of these is the cyclic-production scheme (CPS). This strategy, which requires alternately shutting and flowing wells with high water cut over a predetermined time, enhances sweep efficiency and pressure maintenance and reduces water-handling costs. In a reservoir-simulation model of a mature oil field evaluating a total of 93 wells, simulation runs involving several scenarios showed significant advantage in applying a CPS. Introduction Water management has become a key strategy in fields that have entered a high-water-cut development period. As fields mature, there is a natural tendency for water volumes to increase as aquifer and injected water advances toward the producers. Furthermore, increasing levels of water production can impair oil-production rates, in some cases to the point at which the well ceases to be economical to produce. Although injected water is an enabler for improved hydrocarbon recovery, it is essential to control water-production volumes and the flood front. High water production may limit oil production in a rate-limited well, increasing water-treatment and -disposal costs. One option to reduce water production from high-water-cut wells is to convert to cyclic production. Cyclic wells are alternated between shut-in and producing phases that normally last for 6 months each. The result of closing in these wells is significant water reduction with minimal impact on oilfield production. The main benefit of the cyclic strategy is the reduction of water production, which allows optimization of the water-injection process, minimizing recirculation and allowing a better displacement of the waterflood front to the updip offset producers. Because less injected water is recirculated, the operational handling costs decrease and the economic efficiency of the water-injection project improves. This study was implemented in a mature field as a part of water-management efforts to reduce water production. In this study, a reservoir-simulation model was developed on the basis of very fine geological characterization, and the field-performance history was matched. The model’s history matching was constantly updated by use of up-to-date reservoir-surveillance, pressure, water-saturation (for flood-front detection), and new-infill-well data. The predictive capability of the reservoir-simulation model is very good. Simulation runs were conducted to analyze and optimize the impact of a CPS on the production performance of the field.

Technology Focus: Water Management (December 2013)

Technology Focus Produced water is an inextricable part of the oil- and gas-recovery process, and it is by far the largest-volume waste stream associated with oil and gas recovery. More than 20 billion bbl of water is produced each year in the United States, and more than 90 billion bbl of water is produced annually worldwide. The management of these large volumes of water is an increasing challenge for the oil and gas industry, not only from a technical and economical point of view but also for all environmental issues related to its management. A substantial part of these volumes is directly reinjected into hydrocarbon reservoirs to maintain reservoir pressure and to displace oil to producing wells. The remaining water is treated for disposal or reuse, which includes injection for enhanced oil recovery and fracture stimulation. Produced-water handling and treatment represents an estimated USD 18 billion cost to the US oil and gas industry. It is estimated that each 1% reduction in water production in the US would save USD 50 million to 100 million. The treatment of produced water can be challenging because of variability in both quality and quantity of the produced-water stream. The quantity of produced water varies significantly over the lifetime of a field. Early on, the water-production rate can be a small fraction of the hydrocarbon-production rate, but it can increase with time to tens of times the rate of hydrocarbon produced. In terms of composition, the changes are complex and reservoir-specific because they are a function of the formation lithology, the oil and water (both in-situ and injected) chemistry, rock/fluid interactions, production type, and required additives for oil-production-related activities. Many different types of technologies are available to treat produced water; however, the types of constituents removed by each technology and the degree of removal must be considered to identify potential treatment technologies for a given application. For some types of produced water, more than one type of treatment technology may be capable of meeting the contaminant-removal target, and a set of selection criteria must be established to narrow down multiple treatment options. The papers featured this month deal with produced-water-treating systems, produced-water-reinjection design, and water management. I hope you enjoy reading the selected papers and will search for additional papers in the OnePetro online library. Recommended additional reading at OnePetro: www.onepetro.org. OTC 24199 Water Management for EOR Applications—Sourcing, Treating, Reuse, and Recycle by Lisa Henthorne, Water Standard, et al. SPE 165356 Water Management in Mature Oil Fields Using Preformed Particle Gels by Ali Goudarzi, The University of Texas at Austin, et al. SPE 165693 Maximizing Flowback Reuse and Reducing Freshwater Demand: Case Studies From the Challenging Marcellus Shale by Kushal Seth, Baker Hughes, et al. SPE 163803 Aeration and Microfiltration for Solids Removal of Produced Water From the Barnett Shale by Tor H. Palmgren, M-I Swaco, et al.

Application of Horizontal Wells to Reduce Water Production during Gel Treatment

It is well known that gel treatment has outstanding potential to delay water breakthrough and reduce water production. However, it causes the decrease of oil production by permeability reduction, even though it is not as much as reduction of water production. For this reason, to improve oil production with substantial reduction of water production, performances of gel treatments through the combination of horizontal and/or vertical wells were assessed and compared. An extensive numerical simulation was executed for four different well configurations under gel treatment associated with waterflood to accomplish the purpose of this study. Performances were compared according to cumulative oil recovery and water-oil ratio at the production well for different systems. Though all of well configurations considered in this study effectively decreased the water production compared with waterflood, applications of horizontal wells led to much higher oil recovery than vertical well because of improved sweep efficiency. Based on these results, the potential of horizontal wells was examined through different scenarios in combinations of injection and production wells. Furthermore, various well lengths of injectors or producers were assessed for horizontal wells. Because cross-flow between layers dominates performance of gel treatment, effects of vertical permeability were also investigated in application of gel treatment with horizontal well. Longer wells and higher cross-flow results in better performance. This study represents that effectiveness of horizontal wells for gel treatment even for reservoirs having dominant cross-flow.

Water production in enhanced coalbed methane operations

Coalbed methane (CBM) formations provides a considerable amount of the US natural gas production and have the potential of storing significant amounts of carbon dioxide (CO2) through enhanced gas recovery operations. Enhanced coalbed methane (ECBM) recovery by injection of CO2 or a mixture of CO2 and nitrogen (N2) has been proven to recover additional natural gas resources. However, since coalbeds are normally saturated with water and can be in communication with an aquifer, a large amount of water is often co-produced during the natural gas extraction.The conventional approach for CBM production relies on the reduction of the gas partial pressure in the coal seam. This can be accomplished by either pumping the formation water to the surface and/or by injecting gases such as N2 and CO2. Disposal of the produced water is an environmental challenge as harmful impurities must be removed by appropriate purification techniques. Consequently, a reduction of water production in CBM operations is desirable.In this paper we present a numerical investigation of the potential reduction in water production during ECBM operations that are commonly used to increase methane (CH4) recovery. We use a three-dimensional coalbed model with an aquifer located at the bottom to investigate the amounts of gas and water produced in ECBM operations per volume of coal seam as a function of aquifer strength and sorption characteristics including sorption induced strain. The amount of gas/water that is produced varies significantly depending on the aquifer strength and injection gas composition. We demonstrate that injection of CO2 and/or N2 in some settings reduces the water handling problem substantially.CBM is an important worldwide energy source with a large number of formations being excellent candidates for ECBM recovery processes. Our analysis of the interplay between coal characteristics, aquifer support and the resultant behavior in terms of gas/water production provides valuable input for optimization of future planning and operations.

Experimental study of a novel portable solar still by utilizing the heatpipe and thermoelectric module

In this study, an attempt has been made to design a new type portable thermoelectric solar still (PTSS). In the PTSS, a thermoelectric module is used to improve the temperature difference between evaporating and condensing zones. Also, a heat-pipe cooling device is used to cool down the hot side of the thermoelectric cooler. To evaluate the performance of the PTSS, the equipment was tested under the climatic condition of Semnan (35° 33′ N, 53° 23′ E), Iran. The experiments were carried out in 5 days. The measurement of solar intensity, wind velocity, ambient temperature, water production, and temperature of other components, for example, thermoelectric module, water, walls and heatpipe was done in the same manner for each day. The results showed that ambient temperature and solar radiation have a direct effect on still performance but there is a reduction in water productivity by increasing the wind speed. The results also showed that temperature of thermoelectric device was lower than that of walls which indicated on the higher production of water.

How To Apply the Flow Velocity as a Design Criterion in RPM Treatments

Summary The effect of water control using relative permeability modification (RPM) depends strongly on the well's flow rate because the permeability reduction decreases as the flow velocity increases. This will affect the volume and the properties of the injected RPM fluid. This paper discusses how the velocity-dependent permeability reduction can be accounted for in the job design. The approach is to introduce a velocity-dependent permeability reduction and to solve the Darcy law for non-Newtonian flow. Coreflood experiments report permeability reduction as residual resistance factors (RRFw and RRFo). In scaling up to field situations, the reduction in productivity is a better measure. Designing an RPM treatment to a fixed reduction in water productivity demonstrated that low-volume, high permeability reduction is better than larger volumes with lower permeability reduction. In highly productive wells, there may be situations where certain RPM systems fail to reduce the water productivity adequately. By including pressure constraints on the injection of the RPM fluid, the planned pumping schedule is derived. The criteria for increased oil production are reported as a balance between (1) increased drawdown based on the water-cut reduction and improved lift and (2) reduction in oil productivity. The critical oil productivity depends on the water productivity, initial water cut, density difference between the water and the hydrocarbon phases, and true vertical depth (TVD). It is clearly demonstrated that the potential for increased oil production increases by increasing the ratio between the oil- and the water-productivity reduction (M). In addition, M increases as RRFw increases and the treatment volume decreases. The time to restore the productivity from the oil zone, the cleanup time, can be understood through the fractional-flow theory. In theory, the cleanup time can be derived from relative permeability curves or the saturation profiles during the oil back production. Also, the cleanup time was reduced by the use of low-volume, high water-permeability reduction.

Effectiveness of means used for water demand control

The amount of water extracted for municipal, agricultural and industrial purpose has been about 36.6% of total run-off in Korea. The long-term water resources plan by the Ministry of Construction and Transport predicted approximately 340 million tons of water shortage in 2011. Based on the prediction, construction of a new dam was necessary. The Ministry of the Environment (MOE) launched the Water Demand Control Plan in the year 2000 to save 790 million tons of water to avoid construction of new dams. In 2003, the MOE evaluated the achievement of the Control Plan and declared the Plan successfully saved about 450 million tons of water per year using several means. The declared achievement has been examined using the water statistics between 1999 and 2004. The analysis has revealed that the conservation has not been as successful as declared. Actual reduction in water production between in 1999 and in 2004 was only about 116 million tons instead of 450 million tons that the MOE announced. Probably the MOE ...

Dynamic Optimization of Waterflooding With Smart Wells Using Optimal Control Theory

Summary We used optimal control theory as an optimization algorithm for the valve settings in smart wells. We focused on their use in injectors and producers for the waterflooding of heterogeneous reservoirs. As a followup to an earlier intuitive optimization approach, a systematic dynamic optimization approach based on optimal control theory was developed. The objective was to maximize recovery or net present value of the waterflooding process over a given time period. We investigated the scope for optimization under purely pressure- and purely rate-constrained operating conditions, and concluded that: (1) for wells operating on bottomhole-pressure constraints, the benefit of using smart wells is mainly reduced water production rather than increased oil production, and (2) for wells operating on rate constraints, there is generally a large scope for accelerating production and increasing recovery, in combination with a drastic reduction in water production.

Laboratory evaluation of a new, selective water control treatment and its implementation in a North Sea well

A new weak gel consisting of a non-ionic, high molecular weight polysaccharide and an organometallic activator was developed for harsh reservoir conditions. A first field application was performed on a candidate well in an oil field in the German North Sea tidelands in June 1992. The treatment had to be designed for the entire range of the perforated interval. The polymer solution was readily injectable and the activator was added to the last quarter of the injected volume. The treatment was considered successful as the initial increased water-cut could be maintained at a level of 65%, the overall production rate being comparable to that before treatment. However, the desired reduction in water production was not achieved, presumably because formation permeability was higher than estimated. A laboratory post-implementation evaluation was conducted to find out whether a possible further treatment with a stronger gel might be feasible. The results indicate that formulations yielding stronger gels would still be selective and easily injectable and would show a far greater water control potential.

Water Coning Suppression

Abstract Many oil reservoirs in Alberta overlay active water zones which provide well maintained high pressure drives for primary oil recovery. However, such high pressure aquifers create water coning which is the entry of the bottom water into the production well during the primary oil production. Thus, a well can produce a substantial amount of water along with oil at the expense of oil production. Cold, non-condensable gas injection into an oil reservoir with bottom water has been observed as an effective method for water coning suppression thereby extending the economic life of a production well. A project was initiated to investigate the effect of gas injection in suppressing water coning during oil production from an oil reservoir overlaying an active aquifer. The research program included partially scaled, high pressure physical model experiments in sand packs supported by numerical simulations to understand the mechanisms by which injection of gases (such as carbon dioxide and methane) suppresses water coning. Tests with different non-condensable gases showed consistent reduction in water production or reduction in water-oil ratio of the produced fluids. This paper indicates a number of possible mechanisms for the anti-coning effect of gas injection. It is inferred that the injected gas migrates toward the production well along the oil-water interface as a blanket thereby increasing the free-gas saturation. The presence of even a small amount of free-gas creates a three-phase region of oil, water and gas which results in reducing both the relative permeability for water flow and the residual oil saturation. Thus, water production is reduced. The injected gas (if soluble) also dissolves in the oil and reduces its viscosity. When the oil is less viscous and more mobile, the injected gas sweeps a greater volume of oil. Any swelling caused by gas dissolution would also help in more oil displacement. The preceding mechanisms based on gas dissolution may not be significant in reservoirs with ‘live’ oil containing significant amount of dissolved gas. Another minor mechanism is the plugging of pores by the possible in situ formation of viscous water-in-oil emulsion with acidic gas injection. A key result of this research study is the first time demonstration of the anti-coning effect of cold gas injection under controlled laboratory conditions and the investigation also provided a strong support for the development of Alberta Oil Sands Technology and Research Authority's (AOSTRA) commercial Anti-Water Coning Technology (AWACT). Background Water coning is a term given to the phenomenon of the entry of bottom water into a production well. Under static conditions, water being denser than the formation hydrocarbon fluids, remains below the production well. When oil is produced at high rates however, the interface between the oil zone and the underlying water zone rises and imbibes into the oil depleted region near the production perforations as a ‘water cone’ (Fig. 1). The water cone may extend into the wellbore when the upward pressure gradient associated with the flow of formation fluids into the production wellbore balances the hydrostatic head of the resulting elevated water column.