Effective stimulation of infill (child) wells can be challenging: pressure sinks resulting from production of existing (parent) wells can impair child wells’ completions leading to a loss of production potential. Special completion techniques are required to better stimulate the new rock volume and divert the fracture energy away from the depleted zones. This study investigates pre-loading and re-fracking of parent wells as potential Pressure Sink Mitigation (PSM) techniques to minimize fracture asymmetry in child wells. The impact of these techniques on possible production uplift for both parent and child wells are also investigated. A black-oil reservoir flow simulation model was created and history matched to production from three existing parent wells in a Montney field. Three new child wells have been drilled in close proximity (100m-200m) to the parent wells and were subjected to fracture generation and subsequent production. The fracture generation of the child wells was directly modelled in the reservoir simulator with hydraulic fracture conductivity as an exponential function of pressure. The conductivity-pressure relationship of the newly created hydraulic fractures were validated quantitatively to field history data and qualitatively to a third-party fracture creation software. To limit the influence of the depleted zone, water was injected into the parent wells before the child well fractures are created. Since the child well fracture behavior is directly related to the pressure, a theoretical "reservoir pressure vs injected pre-load volume" relationship was generated. From the relationship, a series of simulation sensitivities were performed where the child well fracture creation and successive production were subjected to different pressure (pre-load) scenarios. The production uplift of each scenario over the non-preload base case was calculated to determine the efficacy of the technique and optimum injection volumes. Additionally, the time for the parent wells to return to their pre-child well production levels was quantified. A practical and robust simulation workflow to evaluate a pressure sink mitigation technique was successfully developed using an actual field case in the Montney formation. As infill drilling and high well density become standard operational practice, understanding how to limit the influence of existing depleted wells is essential for optimizing recovery from hydraulically fractured formations.

Hydraulic fracturing technology requires securing sufficient water resources to access and unlock the pores of unconventional formations. Therefore, successful treatment depends on the fracture fluids, which mainly consist of water-based fluids with a low percentage (around 1%) of chemical additives. However, the oil and gas industry is among the largest freshwater consumers: three to six million gallons of water per well based on the number of fracturing stages. As a result, traditional water resources from subsurface and surface supplies are getting depleted, and freshwater is becoming more difficult to access with higher costs associated with continued demand. For example, operator companies in West Texas face many challenges, including a recent increase from USD 2 to 8 per barrel of freshwater. Also, the transportation of raw water to fracture sites, such as the Bakken shale play, has an environmental impact, with costs of up to USD 5 per barrel, while costs of water disposal range from USD 9 per barrel. This paper aims to investigate produced water as an alternative water-based fluid to several fracture fluids, such as crosslinked, linear gel, and high viscosity friction reducers (HVFRs) to reduce environmental footprints and economic costs. The workflow of this research started with a comprehensive review of extant publications, reports, and case studies to summarize the application of produced water with fracturing fluids in unconventional shale plays, such as the Bakken (North Dakota), Barnett (Texas), Eagle Ford (Texas), Wolfcamp (Texas), Marcellus (Pennsylvania), and Periman Bain (Texas). The critical review begins with explaining the features of produced water, its challenges, and water management options. Furthermore, the different fracturing fluids in a high TDS environment are described using recent lab fluid characterizations of produced water as 10% to 50% of produced water usage at a temperature range between 70 to 210 deg F. Moreover, 2D and 3D pseudo frac simulations are utilized using real field data from the Middle Bakken Formation to construct reliable models to evaluate the feasibility of reused water in shale plays development. The outcomes show that recycling water with high TDS in a high-temperature environment can create a fracture network and proppant transport when high viscosity friction reducers with surfactant (HVFR-PRS) was used. In addition, the result of this critical review is a powerful tool for predicting the future of hydraulic fracturing technology, which might help operator companies reduce costs and develop unconventional wells successfully for a return on their investment. The opportunities and challenges conclusions of water management are provided a survey of future hydraulic fracturing applications in North American shale plays by offering recommendations of environmental and economic impacts. The general guidelines obtained can promote the sustainability of using hydraulic fracturing treatment to produce more oil and gas from unconventional resources without compromising on environmental issues.

This paper presents the successful implementation of an innovative approach for improving oil recovery by water injection optimization with Injection Control Devices (ICD's) in unconventional reservoirs. Over the past decade, operators in Southeast Saskatchewan have been continually innovating and finding efficiencies to improving water injectivity across horizontal wellbores. In late 2016, the Crescent Point Energy started a trial campaign applying ICD's in relatively low flow rate environments to offset production decline and improve recovery in the Bakken, Shaunavon and Midale formations. Early term results show greater than 25% improvement is possible in oil recovery over typical waterflood configurations. The operator had applied waterflood as a secondary recovery method and found field trials to stabilize production decline and improve ultimate recovery. The effectiveness of waterflood in unconventional, fractured reservoirs has been debated. In some cases, short circuiting of injection water to production wells through fracture channels has occurred. This has been found to reduce sweep efficiency. The issue was evaluated and it was determined there was a need to equalize the injection profile across the horizontal wellbore. Understanding the flow profiles of injection wells was instrumental in developing diversion strategies. Applying Distributed Temperature Surveys (DTS) has been found to be an effective method of estimating flow profiles at relatively low flow rates. Using processed DTS data, a reservoir simulation model has been used to match unique injection profiles along horizontal wellbores. The results from these models supported the need to pursue injection diversion. Several means to optimize injection profiles have been trialed, the results of which support the theory of sweep optimization. However, the limited number of isolated injection points achievable with given wellbore diameters has impeded potential for this development. The introduction of ICD injection strings allows for an optimum number of injection points, improving sweep efficiency and accelerating voidage replacement. This paper reviews the design, execution and evaluation process used in more than 50 successful ICD installations in various fields across Saskatchewan. The performance of these ICD strings was then monitored and evaluated in collaboration with the operator and service providers.

Conventional oil production has occurred from the Bakken Formation in Saskatchewan since the mid-1950s. However, with successful implementation of multi-fractured horizontal well (MFHW) technology, the low-permeability (unconventional) Bakken has experienced ever increasing E&P activity on both sides of the US/Canada border. Prior to 2005, the Bakken in Saskatchewan had less than 100 active producers in the region but has increased to more than 2,500 producing wells since then ( Sekar, 2015 ). Although improvement in hydraulic fracture properties and infill drilling remain the focus of recovery enhancement from the Bakken, low oil recoveries and steep initial oil decline rates are experienced using primary recovery operations, even after application of MFHW technology. Therefore, many pilots have been executed to determine the viability of waterflooding for maintaining oil rates and improving recoveries through reservoir pressure maintenance and sweep efficiency enhancement. This paper presents the performance results from one of the waterflood pilots in the Viewfield Bakken. MFHWs were used as both injectors and producers for this pilot. Five years of production/injection volumes for these wells, along with pressure data, were matched using a black-oil simulator. The calibrated model was then used to predict the long-term performance of the pilot. Finally, this model was used for further investigation of parameters affecting the performance of the waterflood operation along with assessment of EOR (gas injection) schemes applicable to the Bakken Formation. Two important conclusions can be derived from this study: 1) waterflooding can be effective in tight oil reservoirs using MFHWs as injectors and producers and, 2) careful characterization of vertical changes in reservoir quality using laboratory-based measurements are important for improving the quality of the history match and resulting forecast scenarios. For 2), permeability heterogeneity was quantified using profile permeability measurements corrected to ‘in-situ’ stress conditions.

In the literature, improvement of oil recovery in smart water injection schemes has been shown to be mediated by wettability alteration. This process reduces residual oil saturation, which in turn affects the microscopic sweep efficiency and leads to subsequent enhancement of overall waterflood performance ( Willhite, 1986 ). Tight and very tight oil reservoirs are often associated with high clay content and significant Cation Exchange Capacity (CEC) values ( Breeuwsma et al., 1986 ). CEC directly influences smart waterflood behavior as it controls ion exchangeability between the solid and aqueous phases, which then regulates the double layer thickness and the wettability of the system ( Nasralla and Nasr-El-Din, 2014 ). This study presents the effect of lithology on CEC value. Experimental studies on smart waterflooding in tight oil cores have reported reduction of residual oil saturation by as high as five percent and improvement of microscopic sweep efficiency by six percent ( Xie et al., 2015a , 2015b ). The promising potential of smart water in tight and very tight oil reservoirs is similarly shown in numerical simulations, in which oil recovery is improved by three percent. Smart water may additionally retard water production by reducing water relative permeability. Furthermore, it enhances effective porosity/permeability through mineral dissolution. However, in tight oil reservoirs, pressure maintenance efficacy could be an issue. Simulation results display a significant pressure drop in the reservoir, which could lead to gas phase liberation and liquid relative permeability reduction. Currently, few studies on smart waterflood in tight and very tight oil reservoirs exist. This work examines smart waterflood opportunities in these reservoirs from both an experimental and a numerical perspective.

A successful waterflood can be implemented in a multi-layered tight oil reservoir developed with horizontal multi-fractured wells. This paper forecasts the recovery factor that can be achieved in such a reservoir as well as discusses the challenges of analyzing and modelling tight oil reservoirs developed with multi-fractured horizontal wells. With some unconventional reservoirs that are hydraulically fractured, a phenomenon exists whereby material balance and simulation indicate pressure support from a water source that is not always obvious. This phenomenon is believed to be related to the multi-layered silts/shales in the reservoir and is not typically seen in simulation of conventional higher permeability reservoirs (K air >10 mD). Although, the exact petrophysical nature of the silts/shale reservoir layers in this project are not well defined at this time, a successful production history match can be achived by incorporating their input into a simulation model.

The Bakken is one of the most prolific plays in North America, but even with the deployment of horizontal wells and hydraulic fracturing, anticipated recovery factors under primary depletion are usually in the range of 10% to 20%. Waterflooding has been a nearly ubiquitously deployed technology in conventional reservoirs to enhance recovery beyond primary depletion. However, the Bakken's ultra-tight, largely oil-wet nature limits the potential of waterflooding. Moreover, the challenges associated with sweep after the formation has been hydraulically stimulated must also be overcome. To address these challenges an optimally-spaced well to well surfactant flooding technology is proposed. Optimal well spacing, from a flooding perspective, can mitigate rapid breakthrough while minimizing the distance through the matrix that the injection fluid must travel. An optimally designed chemical system can enhance imbibition rates and favorably alter wettability to enable economic recovery. Moreover, environmental and community benefits can be realized by utilizing abundant produced water to operate a surfactant flooding process in the Bakken. This paper discusses a comprehensive experimental program exploring the potential of surfactant flooding in the Bakken along with a field communication study and corresponding scaled-up, well-to-well flooding models for an optimized surfactant flooding process. Results from the experimental program are provided which showcase the potential of advanced chemical systems. A brief overview of a core-scale natural fracture study and field-scale well-to-well communication study is provided. Lastly, up-scaled models, showing the potential societal and economic benefits that can be attained from an optimally designed surfactant flood, are presented.

As industry moves towards waterflooding horizontal wells, monitoring and maintaining the injection profiles has emerged as a reservoir management issue. Heterogeneities in the reservoir, completion design, and completion problems can all contribute to non-uniform injection and a corresponding drop in waterflood efficiency. Knowing where the water is being injected along the length of a horizontal water injection well is critical to maximizing secondary recovery. Operators need to monitor for channeling of water injection between horizontal injectors and horizontal producers and gather information capable of determining the best way to remediate problems. Operators have begun using distributed temperature sensing (DTS) to measure the temperature along a horizontal well and infer the injection profile from that data. Based on this information, a workover can be done to redistribute the injection, resulting in lower watercuts at the producers and improving the secondary recovery factor. This paper covers the techniques used to determine the injection profile with DTS, focusing on a case history from the Cardium formation in the Pembina area of Alberta. The well and reservoir conditions are summarized, the completion is reviewed (with microseismic data showing fracture geometry on the injection well), the injection profiling methods are covered, and the results are shown. The operator's remedial efforts are then covered, along with preliminary results.

The evolution of producing resource plays in Saskatchewan Canada has gained momentum in the last 10 years. Many new tight formations in Western Canada have been discovered or are now economic to bring on production due to the emergence of horizontal drilling and hydraulic fracturing technologies. One play gaining momentum over the last few years has been the Lower Shaunavon located in the south west quadrant of Saskatchewan. Through learning's from tight oil plays, such as the Bakken, Crescent Point has been able to apply some of the development strategies to the Lower Shaunavon; however, there is still a large factor of uncertainty and risk involved in these tight formation plays. Reservoir modelling can be used as a tool to reliably forecast well performance and reduce future risk and uncertainty. An eighteen well numerical simulation model was built to represent Crescent Point Energy's Lower Shaunavon waterflood pilot area. Numerical simulation was used as a tool to obtain a better understanding of the reservoir and hydraulic fracture parameters in the area along with waterflood response in the tight oil play. A history match on the pilot area was performed. Using parameters obtained from the history match, a representative model was built and a sensitivity study was performed on hydraulic fracture spacing and well spacing in both primary depletion and waterflood scenarios. This paper will discuss the workflow, challenges, and general findings related to waterflood performance on Lower Shaunavon. While industry continues to study and optimize hydraulic fracturing decisions, the combination of these decisions with IOR potential, namely waterflooding tight oil plays, needs to be understood. Developing a workflow that enables optimization of both fracture completions (spacing, half lengths, etc.) and water injection schemes may lead to a more complete approach to maximizing asset value.

Over a thousand well pairs in five different fields in Western Canada have been examined using communication analysis techniques. The results of this analysis strongly suggest that in addition to conventional Darcy type flow through the matrix rock, there is also strong communication between wells through induced fractures, and/or natural fractures. Most of these five fields are not typically thought of as naturally fractured. Nonetheless this type of fracture flow exists. It is highly likely that these hot streaks are pressure sensitive and therefore have a geo-mechanical component that controls permeability. The geo-mechanical component means that permeability can vary with time and injection pressure. This work on the Western Canadian Sedimentary Basin (WCSB) is similar to work done by Heffer in the North Sea.

In this paper, techniques have been developed to experimentally and numerically evaluate performance of waterflooding and CO 2 flooding for unlocking oil resources from tight formations. Experimentally, core samples collected from a tight formation with a permeability range of 0.081–0.790 mD are used to conduct a series of coreflooding experiments. The performance of four flooding schemes, i.e., waterflooding, near-miscible CO 2 flooding, miscible CO 2 flooding, and water-alterneating-CO 2 flooding, are evaluated by the coreflooding experiments. The continuous CO 2 flooding processes under either miscible or near-miscible condition lead to a superior oil recovery performance in comparison with the waterflooding process. Furthermore, the miscible water-alternating-CO 2 flooding in tight cores leads to a higher recovery efficiency with less CO 2 consumption compared to the continuous CO 2 flooding processes. Most importantly, in the miscible water-alternating-CO 2 flooding process, it is found that the pressure drop increases rapidly when water is injected, but decreases dramatically when CO 2 is injected. This indicates that CO 2 injection is able to significantly improve the fluid injectivity in tight formations. In general, the miscible water-alterneating-CO 2 flooding process is found to be the most favorable flooding scheme for tight formations in terms of both recovery efficiency and fluid injectivity. Theoretically, numerical simulation is performed to match the experimental measurements obtained in the different flooding schemes. There exists a generally good agreement between the experimental measurements and simulated results for all the flooding schemes examined. The tuned numerical model is then employed to optimize the production pressure in the continuous CO 2 flooding process and the water-alternating-gas (WAG) ratios in the miscible water-alternating-CO 2 (CO 2 -WAG) flooding process, respectively. It is found that the optimum producing pressure in the continuous CO 2 flooding process can be set as the minimum miscibility pressure (MMP) of the tight oil sample, while the optimum WAG ratio falls in the range of 4:1 to 8:1.

For stratified reservoirs with free crossflow and where fractures do not cause severe channeling, improved sweep is often needed after water breakthrough. For moderately viscous oils, polymer flooding is an option for this type of reservoir. However, in recent years, an in-depth profile modification method had been commercialized where a block is placed in the high-permeability zone(s). This sophisticated idea requires (1) the blocking agent must have a low viscosity (ideally a unit-mobility displacement) during placement, (2) the rear of the blocking-agent bank in the high-permeability zone(s) must outrun the front of the blocking-agent bank in adjacent less-permeable zones, and (3) an effective block to flow must form at the appropriate location in the high-permeability zone(s). Achieving these objectives is challenging but has been accomplished in at least one field test. This paper asks: When is this in-depth profile modification process a superior choice over conventional polymer flooding? Using simulation and analytical studies, we examined oil recovery efficiency for the two processes as a function of (1) permeability contrast, (2) relative zone thickness, (3) oil viscosity, (4) polymer solution viscosity, (5) polymer or blockingagent bank size, and (5) relative costs for polymer versus blocking agent. The results reveal that in-depth profile modification is most appropriate for high permeability contrasts (e.g. 10:1), high thickness ratios (e.g., less-permeable zones being 10 times thicker than high-permeability zones), and relatively low oil viscosities. Because of the high cost of the blocking agent (relative to conventional polymers), economics favor small blocking-agent bank sizes (e.g. 5% of the pore volume in the high-permeability layer). Even though short-term economics may favor in-depth profile modification, ultimate recovery may be considerably less than from a traditional polymer flood.

In this paper a laboratory study was reported for investigating a method to improve sweep efficiency by applying alkaline flooding for Pelican Lake reservoir. This included interfacial tension measurements, micromodel observatios and channelled sandpack flood tests. In total, 48 flood tests were conducted in channelled sandpacks to evaluate the chemical formulas and injection strategies for Pelican Lake oil. The first 14 sandpack flood tests were carried out to assess the potential of the alkaline flooding for the oil. The results suggested that 0.4 wt% NaOH and 0.2 wt% Na 2 CO 3 was the optimum combination to maximize the oil recovery efficiency in the channelled sandpacks. Based on industry interest in using a NaOH-only slug injection, in the second step 34 flood tests were conducted with the injection of only NaOH solution. For Pelican oil, 0.6 wt% NaOH was the optimum concentration to maximize the oil recovery efficiency (~15% IOIP recovery) in NaOH-only injection. The sandpack flood results obtained in this study showed that formation of water-in-oil dispersion and improvement of sweep efficiency in channeled sandpacks did occur in the tertiary recovery process through the injection of NaOH-only solution.

The Medicine Hat Glauconitic C reservoir contains medium heavy oil, and was put on production in 1985. In 1993, a waterflood pilot was initiated; in 1996, several horizontal wells were drilled as producers, and they resulted in a spectacular increase in oil production. In 2001 a conventional field-wide waterflood was implemented. The waterflood included seven T oe- T o- H eel W aterflooding (TTHW) modules involving 10 injectors and 18 horizontal producers, out of a total of 52 injectors and 100 producers. Five of these modules that utilized vertical wells as injectors performed well; oil rate increased 2 to 11 times, as increases in oil production continued for several years, or stabilized. During the same period, the performance of conventional waterflood modules was characterized by reductions in decline of oil production trends. Two TTHW modules that used horizontal injectors performed similar to conventional waterflood modules. The best performance was shown by Module # 5 (involving two horizontal producers and two vertical injectors), located in the best quality reservoir. Compared to conventional waterflood pilot area nearby, the performance of Module #5 was superior, with oil production rates increasing 7-11-folds, while in the pilot area this was only 2-3 times; the water injected/oil produced ratio was 12–15 m 3 /m 3 for Module #5, while it was 24–44 m 3 /m 3 for the pilot area. The incremental oil recovery due to waterflooding from the TTH module # 5 was estimated at about 7%, and 5% from a nearby conventional waterflood area. A statistical analysis for the whole field revealed that TTH horizontal wells produced at oil rates 30% higher than the non-TTH configuration horizontal producers.

The polymer flooding technology in high and medium permeability reservoirs has been applied commercially in Daqing Olifield since 1996. It has become an important supporting technology for both the stable output of Daqing Oilfield and the development improvement of the mature oilfields. In order to study EOR method in low permeability(less than 100mD) reservoirs, pilot tests of polymer flooding were performed in Daqing oilfield. According to the research results, the low-molecular weight polymer (400800 Dalton) can be continuously injected into low permeability reservoirs under the specified well spacing. Pilot tests of polymer flooding show that oil production was increased from 1.06 tons/d to 3.04 tons/d and water cut was decreased from 96.0% to 89.8% in low permeability reservoirs. Formations with extra-low permeability(less than 10mD) are not flooded effectively in the process of polymer flooding. Production performance of polymer flooding in low permeability reservoirs can be improved by measures of fracturing or separate zone injection with different molecular weight polymers. Comparison and analysis on injection profiles and productivity profiles at different injection polymer parameters showed that the polymer solution with low-molecular weight and relative high concentration was suitable for polymer flooding in low permeability reservoirs. Numerical simulation and pilot results both showed that more than 5% OOIP were obtained by polymer flooding over that of water flooding in low permeability reservoirs in Daqing oilfield.

NFR represent over 20% of the world's oil and gas reserves. However, characterization of fractured reservoirs is complex and presents unique challenges in comparison with conventional reservoirs. It is immensely difficult to achieve the best results in secondary recovery process. This paper presented the successful developments of waterflooding to overcome the complex geological characterizations of White Tiger field - the biggest fractured basement reservoir up to now on the continental shelf of Viet Nam. This reservoir has a complicated geological structure, very high heterogeneity, high temperature and closure stress. The total OIIP of this field reached nearly 4 billion barrels with 2000 meters of the oil bearing thickness and has been produced by more than 100 wells, tens of which flow at the rate of approximately one thousand barrels per day. The geological study and fractured model were carefully investigated in both micro and macro scales to improve waterflooding performance. The authors analyzed the advantages and disadvantages of injection systems in basement reservoir during 20 historical years. And then, the artificial water buffer solution was proposed to develop waterflooding process. The authors described the establishment and the association of local artificial water buffer in basement reservoir. An effective method to adjust the injected water mass was also discussed. The excellent results in White Tiger field proved that average reservoir pressure and total oil recovery were significantly increased in comparison with previous injected schemes. This paper is the precious guideline to solve some typical problems of waterflooding in fractured basement reservoir such as: What could be applied waterflooding in basement fractured reservoir? What is the optimum injected rate and injected mass for basement fractured reservoir? How to evaluate the probability of high water cut in production wells during waterflooding process? How to predict the rising of artificial water-oil contact?

For heavy oils with viscosities ranging from 1,000 to 10,000 mPa·s (cP) in Western Canada, primary production and waterflood together can only recover 8 – 15 % original oil-in-place (OOIP) at their economic limit due to the adverse mobility ratio, severe water channeling and low reservoir pressure and formation voidage. These heavy oils usually have a relatively high content of acids which can react with alkalis to form in-situ surfactants. The loosely consolidated sandstone formations where these oils are deposited are characterized by high porosity, permeability and low reservoir temperature. These reservoir conditions are favorable for polymer application. Therefore, there is a potential to improve waterflood in these reservoirs by applying alkaline/polymer (A/P) flooding. This paper presents the results of a laboratory study of A/P flooding for heavy oil recovery, including viscosity measurements, flood tests conducted in channeled sandpacks, residual resistance factor (Frr) determination, and residual oil distribution tests. A heavy oil with a viscosity of 1,202 cP and an acid number of 1.07 (mg KOH/g-oil) and produced brine collected from a heavy oil reservoir in Alberta are used in this study. The experimental results show that addition of polymer to alkaline solution reinforces stability and strength of in-situ formed emulsions. It is found that the distribution of the injected chemical solution into the high permeable cannels leads to the diversion of the subsequently injected chemical solution to low permeable zones with higher oil saturation due to the formation of blockage in the channel zones. Consequently, pressure build-up during chemical slug injection is the key to the improvement of displacement efficiency. Flood tests also show that alkaline-polymer flooding is more efficient than either alkaline flooding or polymer flooding. The optimal formulation for the heavy oil used in this study is 0.4% NaOH + 0.2% Na 2 CO 3 + 1,000 mg/l polymer, with a tertiary oil recovery of 25 – 30 % OOIP over waterflood. Analysis of the results of the residual oil distributions in the channeled sandpacks at the end of A/P flooding shows that A/P flooding can effectively improve the sweep efficiency of waterflood for the heavy oil.

We have performed a miscible CO 2 flood study using heterogeneous carbonate cores and 31°API west Texas oil to evaluate oil recovery under four injection modes: simultaneous water and CO 2 (SWACO 2 ), water alternating CO 2 (WACO 2 ), continuous gas injection (CGI), and waterflood (WF). For WACO 2 and SWACO 2 injection modes, three salt concentrations are used: 0, 6, and 20 wt. %. For WF, two salt concentrations are used: 0 and 6 wt. %. The experimental results may be summarized as follows: For injected water with 20 wt. % salt concentration, the oil recoveries for SWACO 2 and WACO 2 are 81 and 74 % oil initially-in-place (OIIP), respectively. For 6 wt. % salt concentration, the oil recoveries for SWACO 2 and WACO 2 increased to 90 and 86.5% oil initially-in-place (OIIP), respectively. With injected pure water (0 wt. %), the oil recoveries for SWACO 2 and WACO 2 increased to 98 and 92 % OIIP, respectively. The waterflood oil recovery remains the same at 54% for both salinity levels indicating that dissolved CO 2 is the critical factor in oil displacement. Literature data suggests that CO 2 solubility in water increases when salinity of the injected water is reduced. The low salinity water with CO 2 appears to increase the microscopic oil displacement efficiency.

A gas production system from methane hydrate (MH) sediment layers by combination method with hot water injection and bottom hole pressure control at production well using radial horizontal wells has been proposed. Firstly, gas production characteristics by the depressurization method with bottom hole pressure control have been evaluated by numerical simulations of cylindrical homogeneous MH layer model. The cumulative production gas amount or MH recovery ratio were limited with the pressure reduction from MH equilibrium pressure, because the sediment pressure must be suppressed to keep mechanical stability of sediment layers under the sea bottom. Furthermore, effects of numerical bock modeling and averaging physical properties of MH layers have been discussed as those numerical simulation errors against the original deposit model show a safety side results to evaluate economic issues in gas amount and production rate. By applying the present production system with combining hot water injection and bottom hole pressure control, the numerical simulation results showed that dissociated region including two wells filled with hot water, named as hot water chamber, is expanded outer ward from the area center of MH layer with continuous gas production. The simulations on gas production by injecting 85°C hot water into the MH layer with 1km× 1km and 20m in thickness by using four pairs of dual horizontal wells 500m in length were carried out. It was found that 2MPa pressure reduction from MH equilibrium pressure made the gas production 2.2 times compared with the case of hot water injection only without pressure reduction control.

The impact of brine salinity and ion composition on oil recovery has been an area of research in recent years. Evidence from laboratory studies supported by some field tests targeting mainly sandstones, has distinctly shown that injecting low salinity water has a significant impact on oil recovery. Although, the potential for carbonates has not been thoroughly investigated, some reported studies have excluded carbonates from this effect. The main objective of this paper is to investigate the potential of increased oil recovery by altering the salinity and ion composition of the injection water for carbonate reservoirs, define the recovery mechanisms, and eventually transform the emerged trend to full-fledged reservoir technology. This paper presents the results of a laboratory coreflooding study conducted using composite rock samples from a carbonate reservoir to investigate the impact of salinity and ionic composition on oil/brine/rock interactions, and eventually on oil recovery. The experimental parameters and procedures were well designed to reflect the reservoir conditions and current field injection practices, including reservoir pressure, reservoir temperature, salinity and ionic content of initial formation water and current types of injected water. Also, this study provides detailed discussion and interpretation for potential mechanisms. The experimental results revealed that substantial tertiary oil recovery beyond conventional waterflooding can be achieved by altering the salinity and ionic content of field injected water. The new emerged trend is distinct from what has been addressed in previous reported studies on topics of low salinity waterflooding for sandstones, or seawater injection into high temperature chalk reservoirs. On the subject of recovery mechanisms, the results showed that altering the salinity and ionic composition of the injected water has a significant impact on the wettability of the rock surface. This was also confirmed by nuclear magnetic resonance (NMR) measurements. The results, observations, and interpretations addressed in this study provided compelling evidence to suggest that the key mechanism for the emerged trend is wettability alteration.