Water production or cross flow during production phase is highly undesirable as it incurs additional costs of water handling at surface and reduces relative permeability of hydrocarbons to flow. Problems associated with water production or its cross flow escalate in depleted and HT wells limiting water shut-off options. Long-term zonal isolation to prevent unwanted fluids and cross flow is challenging in such wells due to the need of proper placement in the targeted zone, compatibility of fluid/tool with the downhole temperature and its sustainability. The use of mechanical plugs including packing elements have limitation of application in some instances due to high temperature and odd sized tubulars. Having the abovesaid limitations, an engineering solution was made by testing and implementing reinforced Polymer Gel (a polymer-based gel loaded with silica sand) providing right angle set properties upon exposure to the given temperatures. The aforesaid combination produces a rigid, robust gel structure ideal for shutoff treatments into fractured, vugular and high permeability formations. Such gels can penetrate deep into the matrix or small fissures where the mechanical packers cannot reach to shut off the excess water. This paper demonstrates the assessments to counter above challenges and application of re-enforced temperature activated anionic polymer for water shut off in candidate wells in Southern & Northern regions of Pakistan.

One of the key challenges for Oil and Gas industry in current (low price) scenario, is efficient handling of mature Assets. This is because of the fact that reasonable amount of hydrocarbons still exist in such reservoirs but in scattered and partially-drained locations. Moreover, lower production rates, combined with ever-increasing costs, hardly satisfies the economic screening criteria for their expansion with new wells. This study presents an approach used on such a Mature Gas Giant in Pakistan, in order to re-vitalize old wells and exploit the scattered sweet spots (still prevailing in reservoir), with the help of a robust engineering and geological strategy. The field under study was discovered in 1950s, in the eastern onshore area of Pakistan. The primary reservoir, under study, is a depletion drive fractured limestone i.e. no pressure support was observed in P/Z data. At present, more than 92% of the EUR has already been produced from this reservoir, which translates to 82% of Field In-Place volume. However, the performances of multiple wells have gone down with time, due to the depletion in Reservoir Pressure and the channeling of water towards producing wells-through the faulted/fractured zone. To cut water production and arrest the Annual field decline of 7-8 %, various activities have been carried out, including cementing, tubing size reductions, chemicals; but all the efforts went in vain. In this paper, a detailed approach is presented, that was taken to tap the undrained areas in the vicinity of the existing producers - suffering from water hold ups and low gas rate problems. The Production logs were used first to identify the water production zone. Afterwards, a comprehensive algorithm was developed to analyze the Geological and Geophysical parameters and identify the undrained prospects while keeping minimal capital exposure. So far, a gain of around 10 MMScfd have been observed with the help of two engineered Sidetracks - which has added around 10 - 15 BCF reserves in our portfolio. The most common issues encountered in a mature asset are liquid loading and water breakthrough. This study illustrates the methodology to resolve such issues with minimum investment towards the end of field life. It focuses on the benefits of sidetracks as a production enhancement tool, to reduce the annual decline. This paper offers an innovative approach, to utilize each geological and engineering data set in a systematic manner, in order to re-work old wells at optimum locations to evade issues affiliated with gas entrapment and water production. In the end, the paper also describes the evaluation process of production gains, geology, well construction, and completion types, that can be adapted to reap maximum rewards in such mature fields.

In Enhanced oil recovery methods, CO 2 is an excellent injecting fluid than water because of its prominent properties which includes non-flammability, non-polarity and non-toxicity. The reservoir pressure is over minimum miscibility pressure (MMP), it also provides for miscible displacement process of multi-contact. The CO 2 injection process has been widely practiced in oil industry in the last decades. In the fractured or heterogeneous reservoirs, the injected gas will mostly passage through the fractures or high permeability layers which present the minimum flow resistance, leaving much of crude oil unrecovered in the low permeability rock-matrix. In this research, a composite polymer gel was proposed for harsh reservoir conditions, such as high salinity (NaCl 15.0 wt%, Ca 2+ 0.8wt% and Mg 2+ 0.8wt %), acid conditions (pH 3.25) and analyzed systematically at laboratory scale, consisting of polymer, cross linker and nanoparticles (silica dioxide). The gel system was characterized by different parameters like viscosity (μ), loss modulus (G″) and elastic modulus (G′) by varying polymer concentration, cross-linker concentration, silica dioxide (SiO 2 ) concentration by using macro-rheology. The micro-rheology was used to calculate mean square displacement (MSD) and elasticity index (EI) of composite gel system. The bottle testing method was used for characterizing the gelation time of composite, gelation code and synergistic mechanism. The macro-rheological results of composite polymer gel proved that elastic modulus (G′) and loss modulus (G″) of composite gel system tends to increase with increment in silica dioxide (SiO 2 ), polymer, cross linker and salinity concentrations. The results of G′ and G″ showed that composite gel have good elasticity at high salinity and acidic conditions. The gelation time observed was 6 days, which is sufficient to pump the gel into targeted zone. The gel code obtained was G at the temperature of 60°C. The elasticity index (EI) in micro-rheological results showed that gel has good elasticity, and MSD curve showed gelling fluid is elastic fluid and bears good stability. The composite polymer gel bears very low syneresis in acid conditions for 60 days at the temperature of 60°C, and having good thermal stability. The laboratory scale research indicates that newly formulated composite polymer gel can be efficiently applied to heterogeneous reservoirs for harsh reservoir conditions and CO 2 shut-off problems, and can decrease the water or gas breakthrough problems by plugging the highly permeable channels and increasing the sweep efficiency from low permeable reservoir to produce the residual oil and ultimately increase the production of oil.

Formation damage associated with water blockage is a common problem in oil/gas producing wells. Water blockage is a damage mechanism which occurs when water saturation increases near wellbore, resulting in reduced hydrocarbon saturation and relative permeability to gas. When pore spaces around the well get nearly saturated with water, it reduces gas saturation to near irreducible level that block the gas flow. It decreases the gas production and may recover naturally by extended flow back or excessive drawdown. However, in depleted reservoirs, gas production may completely be lost and shall require chemical treatment. In this paper, a case study has been presented illustrating the complete loss of production of a gas well owing to the water blockage and the treatment mechanism to restore the production (SPE 102383). Well ‘A’ was drilled in Sindh, Pakistan in 2010 in Lower Goru Formation. Later, the well was put on compression and was found on natural decline. By Feb 2019, well was producing 1.14 MMSCFD gas, 6 BPD condensate, and 43 BPD water with 123 psi FWHP. In March 2019, well was shut-in for the pressure build-up (PBU) survey. However, when the well was opened to flow, there was complete loss of production. Identification of the causes of production loss was a major challenge in designing the job. After analysis of well behavior, gradient survey data and formation properties, it was found that the loss of production was attributed to water blockage caused by prolonged exposure of water. Based on above analysis, a stimulation treatment using Volatile Acid System was designed to address the water blockage. The improved cleanup with volatile acid can be expected for two reasons; (1) increased volatility and (2) lower surface & interfacial tensions (SPE-191292-MS). The increased volatility results in lower water saturation and improving relative permeability to gas. Volatile acid system lowers the surface tension and increases the vapor pressure (gas saturation/relative permeability of gas near the damaged zone) and improves the clean-up of spent acid and retained water. In addition, presence of alcohol in acid system helps in achieving deeper penetration into the rock matrix. The proposed solution of Volatile acid system proved successful not only in reviving well's production but also with a gain in production of about 300%.

With the scarcity of new field discoveries and depletion of existing mature fields, operators in Pakistan are keen on cost-effective rigless solutions to enhance production. In the northern region, one operator was looking to curb the water production of an oil well completed with a jet pump installation. The subhydrostatic nature of the well, naturally fractured reservoirs, and large producing units with multiphase reservoir fluids and active aquifers posed significant challenges for rigless well intervention for water control and zonal isolation. High water cut resulted in oil production loss and made the well uneconomic. An innovative zonal isolation method was required to overcome those challenges. The proposed solution comprised coiled tubing (CT) capable of acquiring real-time downhole measurements through fiber optic telemetry and delivering a through-tubing inflatable packer. The 2 1/8- in. packer was to be set in 4 1/2-in. liner with an expansion ratio of ~2:1. Planning and design considerations included selecting the bottomhole assembly (BHA) and performing pre-job quality checks of the inflatable packer and fiber optic cable. Downhole measurements verified accurate packer setting depth using a casing collar locator (CCL). To achieve adequate packer inflation without jeopardizing the packer integrity and to confirm proper anchoring of the packer onto the casing, downhole CT internal and annulus pressures were continuously monitored. During the first run, the liner tubulars were conditioned across the planned packer setting depth using a high-pressure rotary jetting nozzle. In the second run, the through-tubing inflatable packer was anchored, tested, and ultimately released at the target depth, providing a mechanical isolation above the water-invaded interval. Water shutoff is one of the most challenging remedial operations in the oil and gas industry. During the design stage for mechanical isolation, key steps such as proper wellbore conditioning, accurate placement technique, and effective sealing across the water-bearing zones must be carefully reviewed to increase the chance of success. Conventional CT solutions fall short when it comes to actual tool depth with errors as high as 0.3% being accepted as common. Likewise, critical factors for CT operations in subhydrostatic wells, such as precise control of fluid flow in pressure-sensitive tools and understanding of changing well conditions, are very difficult to validate through conventional CT. An advanced CT solution relying on real-time downhole data combined with a high-pressure rotary jetting nozzle and a through-tubing inflatable packer was able to deliver precise results, reducing the water production from 1,253 B/D to 93 B/D and increasing oil production from 48 B/D to 224 B/D. Furthermore, the production tubing remained in place, eliminating the need for a workover rig. Real-time downhole measurements also served as a safety net so the packer would not inflate prematurely, and to allow validation of downhole conditions throughout the intervention. By leveraging the use of real-time downhole measurements to accurately control the positioning and actuation of high-pressure jetting tools and through-tubing inflatable packers, critical interactions with the formation or the completion are achieved, improving operational reliability while reducing risk of failure for water shutoff operations in subhydrostatic wells with a narrow depth margin between intervals.

Current global energy demand and supply gap needs the best engineering methods to recover hydrocarbons from the unconventional hydrocarbon resources. Unconventional resources mostly found in highly stressed, over pressured, and deep formations, where the rock strength and integrity both are very high. The pressure at which the rock fractures or simply the breakdown pressure is directly correlated with the rock tensile strength and the stresses acting on them from the surrounding formations. When fracturing these kinds of rocks, the hydraulic fracturing operation becomes much more challenging and difficult, and in some scenarios reached to the maximum pumping capacity limits. This reduces the operational gap to optimally placed hydraulic fractures. In the present research study, a novel thermochemical fracturing approach is presented to reduce the breakdown pressure of the high-strength layered formations. The new approach not only reduces the breakdown pressure of the layered rocks but also generate highly conductive fractures which can penetrate in most of the layers being subjected to fracturing. The hydraulic fracturing experiments presented in this study are carried out on four layered cement block samples. The composition of cement blocks is synthesized in this way that it simulates the real rocks. The results showed that the newly proposed thermochemical fracturing approach reduced the breakdown pressure in layered rocks from 1495 psia (reference breakdown pressure recorded from conventional hydraulic fracturing technique) to 1107 psia. The post treatment experimental analysis showed that the thermochemical fracturing approach resulted in deep and long fractures, passing through majority of the layers while conventional hydraulic fracturing resulted in a thin fracture affected only the top layer. Thermochemical fluids injection caused the creation of microfractures, improved the porosity and permeability, and reduces the Young's modulus of the rocks. The new technique is cost effective, non-toxic, and sustainable in terms of no environmental hazards.

Hydraulic fracturing and drilling are commonly and widely used in many formations, particularly in unconventional reservoirs, such as tight sandstone reservoirs and so on. Whereas, during the fracturing or drilling process, large quantities of fluids are lost in the formation. Specially, many gas wells suffer a loss in productivity as a result of liquid invasion into the rock matrix. Liquid invasion is referred to as "water blocking", which is the primary damage that occurs in tight reservoirs and in low-permeability and ultra-low-permeability reservoirs. Some methods and materials, like methanol, are used to eliminate "water blocking", but only providing a temporary solution to the problem. This paper introduces a hydrophobic wettability function and mechanisem that effectively eliminates "water blocking" on the tight sandstone. The results from wettability experiments using tight sandstone show that hydrophobic wettability function on the sandstone surface, making a contact angle greater than 90°. The inner wall of capillary tube changes wettability and the capillary pressure becomes a positive driving force rather than a negative resistance. The experimental studies demonstrate that altering the wettability of tight sandstone to produce a hydrophobic surface is a viable method for recovering permeability and eliminating "water blocking".

Environmental concerns and the economic aspects curtail usage of oil-based drilling fluids (OBDF) during the drilling operations through shale formations. The OBDF is highly effective in controlling the swelling potential of the clay-rich shale formations in oil/gas wells. Hydration of shale formation by water-based drilling fluids (WBDF) leads to several problems such as collapse of boreholes, tight holes and stuck pipe which may preclude further drilling and time loss in rectifying the problems, leading to heavy economic losses. Designing the drilling fluid that reduces the interaction with shale, is important for safe and efficient drilling. This study investigates the new gemini surfactants as shale swelling inhibitors in the field of drilling. To assess the performance of new cationic Gemini surfactants two reliable clay sources were considered. The first clay (Kaolinite) is from an unconventional formation and the second is sodium bentonite. The inhibition characteristics of gemini surfactants were tested using a dynamic swelling tester. Different formulations based on commercially available solutions for shale swelling inhibitors were applied and compared with cationic shale inhibitor. It was observed that the new gemini surfactants reduced the shale swelling by different percentages for various gemini surfactants based on their spacer length. It also showed acceptable performance compare with common shale inhibitors used in the industry.

A major challenge in carbonate reservoirs is the highly-fractured nature of the rock. The flow rate may be high or low depending on the targeted fracture clusters. In addition, it is possible that flow rates vary from one region of the reservoir to another. Smart wells furnished with smart completion strategy presents great prospects to produce such reservoirs intelligently, thereby, helping to deal with heterogeneities rather smartly. It is established that early water break-through occurs when multi-lateral wells are completed with constant choke settings, and therefore one way to mitigate this problem is using smart completions that manage the unexpected production through fractures, thereby increasing ultimate recovery. The early water breakthrough is obvious because if a lateral section intersects a clusters of fracture zone, there is a possibility that these fractures may connect with the water zone that may trigger the breakthrough. This can be managed by preferentially regulating production from manifold laterals. The evident communication among the various laterals of the mother bore raises difficulty in optimizing the production from the variable productivity intervals. In theory, the optimization scheme of smart completion involves different constraints, nevertheless, the settings of the smart inflow control valve (ICV) is the single most important parameter that may prove to be the differentiating factor between a high producing well to a poorly producing one. This study engrosses its effort on the reservoir engineering characteristics of finding the optimum choke setting that would lead to maximum recovery. Computational Intelligence through Particle Swarm Optimization (PSO) is utilized as the integral algorithm to determine the optimal ICV configuration for a fishbone well in a naturally fractured carbonate reservoir. A commercial black oil simulator was used to determine the objective function; whose role here is to evaluate the fitness of a configuration of the choke; this was carried out under a workflow programmed in the MATLAB programming language that coupled the optimization algorithm with the numerical simulator. A single fishbone well, having 15 laterals was studied in order tot see the effect of the fracture network on the water breakthrough and consequent impact on recovery. Three different scenarios are developed to see the impact of optimization; a base case employing only multilateral well technology without the smart well completion, a smart well completion scheme with no optimization and finally the optimized smart well completion. The results very sequentially clarify the need for not only optimization but also highlights the role of intelligent completions for wells in the reservoir being studied. It is evident that without using smart wells, the water breakthrough is relatively earlier and produces less hydrocarbons, but as the use of smart wells is incorporated, the results start improving and for complete optimization scheme of the ICVs, it is observed that the recovery has increased by almost 80% from 21% to 38%. Moreover, the time to water breakthrough and eventually the cumulative water cut has also been managed quiet significantly.

Water blockage is a common phenomenon that significantly deteriorates well deliverability. It is caused by introduction of external water in critical matrix which changes parent saturations thus damaging relative permeability to oil or gas. This paper discusses the case of a gas well that suffered complete loss of production due to water blockage which, however, was later successfully treated and revived using alcohol based recipe. The well K-1 was drilled By UEP in Sindh, Pakistan and encountered hydrocarbon hearing BS-1 and BS-2 Sands. The well was put on commingle production from BS-1 & BS-2. After few months of production, water breakthrough was observed from BS-2 and was subsequently isolated, based on production logging results, using mechanical plug. However, well behavior indicated integrity issue of mechanical plug with well ceased to flow from BS-1. Attempts to revive the well proved futile as K-1 did not revive. Detailed investigations identified that well loaded up due to cross flow of BS-2 water into BS-1 resulting in water blockage. In order to treat water blockage, alcohol based system was used. It is a volatile non-aqueous solvent which basically lowers the surface tension of acid and thereby achieves deeper penetration into rock matrix. Alcohol based recipe proved successful in curing water blockage and reviving the well's production.

Gas compression has been widely adopted by the petroleum industry and is validated as a reliable method for improving reserves base. As depletion drive gas fields mature, their reservoir pressure declines with an associated reduction in gas production rates. This phenomenon is even more pronounced in fields where aquifer water breaks through and results in rapidly falling well head pressures which naturally result in reduced reserves recovery over the producing life of the field. Compression at wellhead or at the facility elongates well and field life resulting in tapping additional reserves, which may be left behind in case surface compression facilities are not put in place in a timely and phased manner. Compression was initiated at Bhit Gas Field from 2009 and implemented in a phased manner over several years. In first phase, well head compression was deployed to ensure a continuous plateau rate and provide additional gas recovery at 100 psig suction pressure which was selected through matching compressor curves against well deliverability. In second phase, booster compressors at selected wellheads were installed to further drop pressures d upto 50 psig. This was followed by optimization where existing compressors were not only swapped, relocated and reconfigured but also spare compression capacity was utilized by merging wellhead to nodal compression to further drop pressures upto 20 psig leading to increased recovery. Surface optimization actions were justified by set of forecasted results from simulation model utilizing compressor curves. This paper will demonstrate the continuous surface optimization performed as a function of reservoir and well response with the ultimate aim of enhancing reserves recovery by comparing actual field performance with Forecasts from a numerical simulation model. Highlights on the benefits of timely identification and implementation of compression needs achieved through significant cost savings and reduced project time to market will also be presented

Poor recovery of oil rims is a common challenge for most operators. The reasons are inherent subsurface risks and capital intensive EOR and IOR projects. This paper presents a similar case of reservoir with oil rim where a cost effective method was employed to increase oil recovery. The idea was to inject high pressure gas from a shallower gas reservoir into zone with oil rim. The case study is about B Field located in Sindh Province of Pakistan discovered through drilling of well B-1 in 1989. The well encountered hydrocarbon bearing Lower Goru X&Y Sands. Formation testing results and Open-hole logs showed X Sand to be gas bearing, whereas, Y Sand found thin oil rim overlain by gas cap. B-1 was put on production from Y Sand and it flowed at around 300 bopd with 500 scf/stb GOR. However, rapid decline in oil rates and reservoir pressure was witnessed due to gas coning. Based on engineering and G&G analysis, it was decided to re-pressurize oil rim in Y Sand using gas of X Sand at virgin pressure. Considering Y Sand to be laterally extensive body, effect of gas injection at B-1 should be observed at wells B-2 and B-6 in the same structure. Nodal analysis was performed to estimate injection rate while tank models were used to estimate additional recovery. The X Sand was then perforated and cross-flow established. Performance of gas injection was monitored through surveillance at B-2 and B-6 that recorded increasing Y Sand pressures. Success of in-situ gas injection was established as considerable improvement in oil recovery was achieved. In-situ gas injection, wherever applicable, could be an efficient technique to maintain reservoir pressure of oil reservoir without additional surface footprints or facilities thus incurring marginal capital expenditure. The efficacy of this technique could be easily monitored through regular surveillance and well production behavior.

The paper presents a case study to improve recovery in a heterogeneous depletion drive oil reservoir by pressure maintenance through waterflooding, which was designed by analyzing seismic attribute and well tests data and incorporating it in a reservoir simulation model. X Field is an undersaturated oil field which has been accessed by two wells. It is an extremely heterogeneous reservoir with X-1 being a prolific producer while X-2 having no production due to significant facies variation in the reservoir over a short distance (~2km). The field displays depletion drive behavior with rapid pressure decline over low recovery. A reservoir simulation study was undertaken to improve recovery and arrest pressure decline. Attribute analysis and well tests data helped address heterogeneity of the reservoir by predicting the facies distribution throughout the reservoir. These learning's were incorporated into a reservoir simulation model and a line drive water injection pattern was determined as the optimal method to improve recovery in X Field. A new well, X-WIW, was drilled to start injection and sidewall cores were acquired from it. Multiple lab tests were performed on these cores to confirm injected water compatibility with the formation while the well's injection rates and surface parameters were closely monitored to help minimize reservoir damage and achieve continuous injection. Using seismic attribute analysis, a good facies zone was identified for drilling X-WIW for line drive water injection pattern. Well results showed good quality sand which laid further credence to the facies distribution model. MDT showed depleted pressure in X-WIW, therby confirming connectivity between X-1 and X-WIW. Sidewall cores were obtained and multiple tests performed, including Capillary Suction Test (CST), XRD Analysis, Sludge Test and Core Flow Test, which showed no presence of swelling clays and good formation compatibility with injection water. Prior to injection, X-1 was shut in to preserve reservoir energy and current bottomhole reservoir pressure was measured. Upon receiving these lab results, injection was initiated successfully, with X-WIW injecting 2500 bwpd while keeping X-1 shut-in. Periodic measurements of bottomhole pressure were taken at X-1 to observe injection response. The pressure at X-1 was measured to be steadily increasing indicating successful voidage replacement. The most significant new finding was the accurate prediction of the pattern of variation of petrophysical properties through seismic attribute analysis and well tests data which enabled X-WIW to be a successful injector and helped in improving the recovery of X Field. Prior to this water injection project, X Field was predicted to have a recovery factor of 21% which has now been improved to 35%. This significant increase in recovery was made possible by the successful implementation of the water flooding project in a heterogeneous and stratigraphically complex field.

Gas Assisted Gravity Drainage (GAGD) is a relatively new gas flooding Enhanced Oil Recovery (EOR) technique developed at Louisiana State University (LSU) to increase oil recovery by application of miscible and immiscible gas injection processes (using CO 2 , N 2 , and hydrocarbon or flue gases). This paper describes the evaluation of application of this technique to a limestone formation in North Western Pakistan using fully compositional commercial reservoir simulator. A sector model was taken out of a full field history matched simulation model for subject gas condensate/oil field in North Western part of Pakistan. A seven component fluid model was developed and calibrated against available PVT experimental data using a commercial PVT modeling package and multiple contact miscibility tests were simulated to estimate Minimum Miscibility Pressure (MMP). Phase behavior calculations indicated minimum miscibility pressure (MMP) to be ~ 5000 psia using 100 % CO2 as an injected fluid. Following this, subject reservoir performance was evaluated by placing wells in different configurations. Oil recovery forecasts were projected for different development scenarios including base case primary pressure depletion, Continuous Gas Injection (CGI), Water Alternating Gas (WAG) injection and Gas Assisted Gravity Drainage (GAGD). Simulations indicate that GAGD is a viable development strategy for said reservoir. However, as soon as, injected gas encounters low pressure near well – bore region across producer, it breaks out through path of least resistance and after breakthrough small production rates are possible, hence increasing post breakthrough project operating expenditure (OPEX). Therefore, key is to delay gas breakthrough for as long as possible. If well placement is properly optimized, GAGD results in a recovery factor of ~ 53 % for said reservoir in comparison to 26 % for base case development scenario. Effect of vertical permeability anisotropy ( kv/kh ratio) is also investigated and indicates that even for a very low kv/kh ratio of 0.1, ~ 50 % recovery factor can be achieved for said reservoir. It is recommended to give due consideration to well placement before commencement of a GAGD project. Before applying this technique on a full field scale, it is recommended to launch a small – scale pilot project for field testing to get more realistic recovery predictions. This work screens and makes case for application of gas EOR in fractured limestone formation resulting in an increment of ~ 27 % in recovery factor in an area where enhanced development techniques are not traditionally practiced.

The research presents an effective way for the optimization of one of the enhanced oil recovery mechanism; surfactant-polymer flooding by the application of two stochastic evolutionary algorithms namely Covariance Matrix Adaptation-Evolutionary Strategy (CMAES) and Invasive Weed Optimization (IWO). The optimized parameters include the well placement, time duration for water and chemical flooding, and chemical injection rates in injection wells while net present value (NPV) served as the objective function. Surfactant Polymer (SP) flooding has proved to be an efficient enhanced oil recovery (EOR) mechanism in recent times. Research has been done on the efficiency of SP flooding by optimizing different properties of surfactant and polymer such that the process results in an improved oil recovery. However, these optimizations are based on the sensitivity studies which limit the researchers to search the optimum solution within a specific domain without extensively exhausted the search space. Stochastic techniques, however, showed a way to efficiently optimizes the SP flooding process even with higher number of optimization parameters. Detailed optimization results for several cases considered in this research are presented. Channeled reservoir and fully heterogeneous reservoir are the two reservoir models used for the optimization of SP flooding process. The maximization of NPV for SP flooding using well placement optimization and without well placement optimization is also compared for both reservoirs utilizing CMAES and IWO. Furthermore, all cases are compared with the base case of simple waterflooding. Statistical analysis is done for all the cases for several realizations and the realizations are ranked according to the best, median and worst, based on the NPV values for each case. The consideration of having such a higher number of optimized parameters is to fully evaluate the potential of considered stochastic optimization techniques to converge to a global maximum for NPV as opposed to conventional sensitivity analysis. Results suggested that these stochastic evolutionary algorithms have a potential to be utilized as the optimization tool for field development of reservoirs having higher number of parameters to be optimized. The successful evaluation of considered stochastic evolutionary algorithms (CMAES and IWO) proved that these algorithms can successfully be used for the optimization of field development plan under higher number of parameters to be optimized that cannot be achieved using sensitivity analysis or gradient based optimization algorithms.

The Retrograde Gas-condensate systems have always been found unique both in their flow behavior and their ultimate recovery. This is mainly because of the process of condensation that takes place around the wellbore creating a region of condensate drop out resulting in flow impedance. In addition to it, the dependency of relative permeabilities on positive and negative velocities due to coupling and inertia respectively, further complicates the flow performance. These factors, thus, make an optimum production from these systems a very challenging and difficult task. Therefore, the main aim of this paper is to present a systematic approach towards the recovery optimization of such a low permeable gas condensate reservoir in Pakistan. There are different production enhancement techniques that are applied to retrograde systems, among which Hydraulic Fracturing (HF) is a very common exercise. This Fracturing, however, also needs the optimization of geometry (i.e. width and length) and flow (i.e. rate) parameters to make it of high value. But, in some instances, despite of the enhanced flow behavior by HF, considerable amount of valuable gas and liquid might still be lost. Therefore, the recovery can be further optimized through techniques such as Water Flood (to increase the pressure back above the dew point), Miscible Gas or CO2 flooding etc. This study first illustrates the impact of coupling and inertia on hydraulically fractured wells, using 3D reservoir simulation on real time data. A one well sector model is initially developed after validating the history match of the whole field model. Afterwards, the data from the Hydraulic Fracturing jobs, is incorporated to evaluate the positive and negative effects of the gas velocity, along with the recommendations on frac-geometry optimization for such gas condensate reservoirs. The paper then illustrates the application of different Enhanced Oil Recovery methods on the whole field, using detailed compositional simulation, keeping in view the limitations of hydraulic fracture – as it may not be the answer to optimized recovery. Eventually, a comprehensive strategy has been presented, summarizing all the factors having maximum influence on the ultimate recovery and illustrate the operational and economic aspects of such technologies, to increase the overall gas and condensate production from the field.

Alkali-Surfactant-Polymer (ASP) flooding is the most effective Chemical Enhanced Oil Recovery (CEOR) method applied in sandstone reservoirs. After the successful results in sandstone formations, its usage has been widened to carbonate reservoirs as well. However, ASP application in carbonate reservoirs is less well understood. The main limitation of ASP flooding in carbonate reservoirs is the presence of carbonate minerals. These minerals react with the added chemicals to form insoluble materials called precipitations. Therefore, an ASP formulation was developed by incorporating acrylic acid as a precipitation inhibitor to overcome the precipitation problems. The performance of the Acrylic Acid (AA) with an ASP formulation was evaluated using sodium metaborate, surfactant and polymer. Feasibility of applying AA with ASP formula was demonstrated by comprehensive fluid-fluid compatibility tests, interfacial tension tests, viscosity measurements and coreflooding experiments. Hardbrine composition of 59,940 ppm was used to prepare the ASP formulations in the presence and absence of AA. All the chemicals including, alkalis, surfactants, and polymers were compatible with the hard brine used in this study. The presence of acrylic acid exhibited excellent properties in preventing precipitations as the all solutions remained clear for 30 days at 80°C. The weight ratio of optimum acid concentration of acid to alkali was found to be 0.6:1.0. No precipitation was observed when using this acid to alkali ratio. Interfacial tension and viscosity tests screened the best chemical formulations which were validated by coreflooding. The core flooding tests showed significant improvement in the oil recovery with the use of AASP and ASP flooding by accomplishing a total oil recovery of 75.7% and 88.7% OOIP respectively. Although, total recovery efficiency of AASP formulation is relatively lower than with ASP, the new AASP formulation can be prepared with any water source such as formation water or seawater. The precipitation inhibitor makes the conventional ASP system more flexible and advantageous for offshore applications by eliminating the need of softening or desalting the seawater. Furthermore, there is no need to remove the calcium and magnesium ions from the injected water as it can be done by using the appropriate concentration of acid and alkali. This eliminates the cost of water treatment equipment and minimizes the use of surface equipment as well.

The underground geological CO 2 storage into oil and gas reservoirs and/or saline aquifers is a promosing technique to reduce anthropogenic greenhouse gas emissions which thus ensures clean environment. CO 2 can also be injected into coal beds and shale formations where it gets trapped by means of adsorption trapping with additional benefits of enhanced methane recovery. In this context, wettability of CO 2 /coal/brine and CO 2 /shale/brine systems plays an important role in governing the suitable storage conditions. Wettability of a given system is a function of injection pressure, reservoir temperature and type of the coal or shale. Despite the vital benefits, relatively less attention has been given to CO 2 injection in coals and shales for storage and enhanced methane recovery purposes. Therefore, in order to access the storage potential in coals and shales, we experimentally tested CO 2 -wettability by advancing and receding contact angles measurement using a drop-pendant titled plate technique for coals of high, medium and low ranks (data taken from previous work) and three organic-rich shale samples of varying TOC at in-situ pressure and temparture conditions. We found that both advancing and receding contact angles increased with increase in pressure and decreased with increase in temperature irrespective of the type of sample analysed. Moreover, at any given pressure and temperature, high rank coals exhibited higher values of contact angles (more CO 2 -wet surfaces) in comparison to low rank coals. Similarly, high-TOC shales were more non-wetting as compared to low TOC shales. In summary, higher the organic carbon content of coal/shale, higher were the CO 2 -wettability of the system under investigation. The increased CO 2- wettability of coals and shales implies that the injected CO 2 will be distributed rather uniformly in organic material of the coal or shale formation thus resulting in better adsorption of CO 2 into the micropores. Moreover, since it is experimentally proven by previous studies that adsorption capacity of CO 2 is up to ~9 times higher than that of CH 4 , therefore, higher CO 2 -wettablity will result in improved displacement of methane towards production wells due to preferential adsorption of CO 2 over CH 4 . We finally conclude that high rank coals and high-TOC shales are better for CO 2 storage and methane gas prodcution due to better CO 2 -wetting and that the benefits are further improved if formation temperature is low and injection pressure is high. The results of this study, therefore, lead to a guideline for optimum coal and shale formation selection for CO 2 injection.

CO2 injection is considered as one of the successful methods used for enhanced oil recovery (EOR) in oil fields to recover residual oil. It increases mobility and reduces viscosity and interfacial tension. Asphaltene precipitation and deposition phenomena appear in petroleum reservoirs due to change in temperature, pressure, and liquid phase compositions; either during the primary production or enhanced oil recovery processes. Asphaltene precipitation might occur due to CO2 injection in light oil (>30° API) reservoirs which may cause blockage of production system, decrease in permeability, wellbore plugging and change in porosity. Experimental data concludes high asphaltenes precipitation and lower asphaltene solubility in light oils. Hence severe damage to formation can happed sue to asphaltene precipitation, in some cases the loss might be irreversible. This paper furnishes the investigation of asphaltene precipitation caused by CO2 injection. In this regards interaction between asphaltene and formation, precipitation quantity under different injection flow rates of CO2 at the constant injection pressure have been investigated. Results conclude that there is direct proportionality between asphaltene precipitation and amount of injected gas in the core sample, whereas inverse proportionality between asphaltene precipitation and increased injection flow rate of the gas at constant injection pressure.

Relative permeability and interfacial tension are key parameters to characterize chemical enhanced oil recovery. Chemical flooding, a modern technique of enhanced oil recovery is based on the principle of reduction in interfacial tension of oil/water system. The selection of suitable surfactant is important and it should be compatible in a single phase solution at reservoir conditions and can be capable of reducing the interfacial tension to about 10–3 dynes/cm. In this study, Alcohol Alkoxy sulfate sodium salt (AAS) has been used as a surfactant. AAS was found compatible for conducting core flood experiment and it also reduced the oil/water interfacial tension to a very low value by forming type III micro emulsion. A Berea sandstone core plug of 100md was used in the core flooding experiment. The experimental results showed significant decrease in water/oil interfacial tension of 29 dynes/cm to 4.15*10–4 dynes/cm. SendraTM estimation was used for the history matching between experimental data with simulated one. Recovery with water flooding was 59.28%, whereas with surfactants it was increased to 85.95%. Relative Permeability of oil was 0.92 with water flooding, whereas relative permeability of oil with surfactant flooding was 0.98. The comparative analysis showed that two phase region (oil-water) becomes wider when surfactant was used and also relative permeability of oil was increased with decrease in interfacial tension. This study shows that surfactants can be applied in most oil fields of Pakistan especially in Central Potwar region where oil API is in the range of 10–22◦, so they promise a bright future for Petroleum Industry in Pakistan.