Reservoir and production engineers rely heavily on well production rates to optimize well activities such as ensuring optimum reservoir monitoring. Individual gas well rates are not readily available, rather, they can be estimated thru multi-phase flow meter (MPFM) and well test analysis. These methods are associated with certain limitations such as high cost, high uncertainty, and technically elaborate calculations. Consequently, empirical and numerical calculations are employed with well test data to calculate daily rates. These practices lead to inaccurate gas rate estimations. A model with an ability to provide accurate estimates of gas rates for a gas reservoir can serve as a handy tool for the subsurface engineers in addressing well and reservoir optimization strategies. This work presents artificial intelligence models to estimate gas rates in a gas field containing ten wells. The aim is to develop a correlation that is simple and easy to incorporate yet providing robust answers on a global scale. Multiple machine learning tools are employed. These include; Artificial Neural Network (ANN), Functional Network (FN), and Adaptive Neuro Fuzzy Inference System (ANFIS). Production data from a dry gas field X was used for the model development. Data cleaning and data reduction steps were carried out to ensure the input parameters for the proposed model are physically relevant and accurate. Missing these steps would result in the development of an erroneous correlation, i.e., garbage -in garbage-out (GIGO). This led to finalization of certain basic well-head parameters which are available at any typical well and had direct impact on the output production rate. The target parameter for model training is the gas rate. A rigorous comparison between the investigated artificial intelligence models was conducted by calculating average absolute percentage error (AAPE) and coefficient of determination. The comparative analysis shows that the intelligent model is able to predict the gas rate in condensate wells with accuracy in excess of 90%. Examples of such large accuracy has not been reported previously. ANN performs a step ahead as compared to the various intelligent algorithms used in this study. This paper sheds light on the potential of the Industrial Revolution 4.0 for the Pakistani Oil and Gas Sector. Data-driven artificial intelligent models are capable of validating the well test and multiphase flow meter results. In addition, it can prove to be a vital tool in an engineer's tool-kit to reduce uncertainties in gas rate measurements.

Accurate fluid placement had always been a challenge in depleted reservoirs. Criticality of such jobs multiplies when cement plug is to be placed in a depleted reservoir or when there is a marginal tolerance in terms of volume or differential pressures for the placement of cement plug. Various techniques are used in industry to spot specific cement slurry volume in stages to get accuracy in plug depth. Bailers being most successful, demerits from having very less volume of cement slurry which can be placed, resulting in multiple runs. To effectively place fix quantity of chemical plug or cement slurry in a well, a coiled tubing conveyed hydrostatic valve (fluid retainer) can be successfully deployed, by placing known quantity of liquid only. In depleted oil and gas wells (especially the ones in secondary recovery phase) there is a static sump present. Reservoir shut off solutions cannot be used in this scenario as the increase in hydrostatic head causes loss of the pill into the the reservoir zone. In such scenarios, cement plugs are preferred to be dumped using dump bailer, however, for volumes larger than 1 bbl bailer option is not feasible. Hydraulics balance is crucial to job success, and such applications virtues the use of a coiled tubing conveyed Hydrostatic Valve. This paper discusses operation of hydrostatic valve and present case studies of two wells in Pakistan, where this technology is effectually implemented together with acid soluble and salt saturated cement slurry.

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.

In Potwar Basin, Tight Naturally Fractured carbonate reservoirs usually have matrix porosity of the 2-3% and permeability less than 1 mD. It is very challenging to evaluate Gas initial in-place (GIIP) and reserves accurately in these type of reservoirs. The objective of this study is to evaluate Gas in-place and to characterize the reservoir energy mechanism using rate transient analysis (RTA). A comparison has also been made for Gas in-place from conventional material balance analysis and from rate transient analysis. In this study, rate transient analysis has been performed in a well, located in Potwar with thirteen years of production history. The well is completed in Chorgali and Sakesar formations. Different scenarios of initial reservoir pressure, geo-mechanical effects during initial production of the well and aquifer volume were sensitized to evaluate the Gas initial in-place (GIIP) and reserves. Different type curves such as Agarwal Gardner, Blasingame and flowing material balance and analytical aquifer modelling with / without geo-mechanical effects were applied and matched with the production history. Production logging data was also incorporated in the study. During history matching (gas-rate and bottom-hole flowing pressure), different sensitivities were run to quantify the uncertain parameters and level of uncertainty in the simulator. While history matching and evaluating GIIP/reserves, it was observed that 8,060 psi reservoir pressure measured in the well was not stabilized and the reservoir was dominated initially by geo-mechanical effects. The best match was achieved with 10,935 psi initial reservoir pressure which was measured in the first well of the field. Without considering this pressure and geo-mechanical effects, the best match could not be obtained. It was also confirmed by different type curves that reservoir was geo-mechanically pressured during the early life of the well and also, it has a weak aquifer support during the late life of the well. The GIIP evaluated from these type curves are in the range of 75-90 BSCF whereas conventional material balance showed 60-70 BSCF indicative volume associated with the well. This study exhibited a significant difference in GIIP/reserves evaluated from conventional material balance and rate transient analysis, indicating remaining hydrocarbon potential in the region i.e. approximately 10-13 BSCF. If the static reservoir pressure is taking too long to stabilize, the conventional material balance approach always depicts lower hydrocarbon volume associated with the well due to the tight and heterogeneous nature of the reservoirs. Therefore, conventional material balance cannot be applied in these reservoirs and unconventional approach such as rate transient analysis should be applied to evaluate GIIP / reserves and reservoir energy mechanism.

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.

The objective of this paper is to investigate the impact of BOEs (Barrel of Oil Equivalent) conversion factor for Gas and LPG with reservoir pressure depletion on production and reserves figures with reference to Petroleum Resources Management System (PRMS) guidelines. In general, it is a common practice of E&P (Exploration & Production) companies to use same BOEs conversion factor for Gas (especially wellhead) and LPG throughout the life of reservoir. However it is understood that Gas and LPG composition plays a vital role on conversion factors of BOEs used which has an impact on the wellhead production figures, well head reserves booking, field economical limit and etc. In this paper, "XYZ" field is considered to evaluate the impact of BOE conversion factor on wellhead gas and LPG. The "XYZ" field is producing gas condensate from HPHT (High Pressure & High Temperature) fractured carbonate and clastic reservoirs in upper Indus basin of Pakistan. The field was discovered in early 1990’s and produced ~ 70 BSCF of gas till to-date. The standard BOE gas conversion factor for "XYZ" field is 5.80 MSCF/STB which gives 1,224 BOEPD on current production data and expected remaining recovery of around 40 MMBOE. The recent BOE conversion factor based on current gas analysis is found to be 4.46 MSCF/STB that translates 1,500 BOEPD and expected remaining recovery of 46 MMBOE based on average reservoir wise BOE conversion factor of 5.13 MSCF/STB. LPG is based on 70% propane & 30% butane, therefore its fixed composition restrict us to use a BOE conversion factor in the range of 11.60 to 11.84 MT/D. BOE estimation and results in this paper conclude that the change of BOE factor depend upon the change in gas composition with production history at wellhead and depletion in reservoir pressure. Based on this working, wellhead production figures, well head reserves booking and etc for XYZ field have been revised. This also dictates the importance of booking these figures at sale condition.

Hydraulic fracturing is the technique which is key to success in developing Shale/ Tight Reservoirs. Hydraulic frac job cost is a challenge which sometime is more than the actual drilling cost while 70% of that pertains to the products (i.e. Fluid, proppant etc). Major components of frac fluid consist of Guar while proppant consist of sand/ synthetic sand. Pakistan is one of the guar gum producer country in the world along with long coastal area with abundant sands, covering the wide range of stresses. So far, no research has been undertaken to make this technique economical therefore, utility of indigenous resources needs to be explored. Cost optimization of this technique using indigenous resources will help in untapping these resources at booming economy, helping in saving petrodollars and in the meantime generating a huge volume of economic activity in the country. This paper describes the need for researching on indigenously developed frac fluid and sand used as proppant to improve well productivity.

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.

In matrix acidizing of carbonate formations, acids are used to create wormholes that connect the formation to the wellbore. Hydrochloric acid, formic or acetic acid, or mixtures of these acids are commonly used in matrix acidizing treatments of carbonate reservoirs. However, the use of these acids exhibits some major limitations including high and uncontrolled reaction rate, face dissolution and corrosion to the completion goods, especially those made of chrome-based tubulars (Cr-13 and duplex steel), and these problems become severe at elevated temperatures. This paper presents a case study of a post datafrac operation wherein a state-of-the-art stimulation system, based on a chelating agent, is deployed in a matrix stimulation treatment of a low temperature tight carbonate reservoir for the first-time in the country. The new stimulation fluid allows the operator to optimize datafrac and wellbore stimulation in a single treatment. The approach also aids the project to be cost-effective and financially feasible, particularly in a low-budgetary environment. Literature review comparing selected chelating agent and conventional acids is also described in this paper to support the approach adopted in abovesaid case study.

With the continuous increase in global energy demands, it has become imperative to get the most out of the existing reserves in developed fields. While focusing on maximizing productivity, the conventional methods of well completions are not always optimal. Cemented Liner Completions in multi-layered reservoirs can at times be in-efficient and thereby create issues of zonal isolation and well integrity, besides causing irreversible damage to reservoir sections. To overcome these obstacles, and to provide an added advantage of selective stimulation in multiple zones, industry is gradually moving towards open-hole multi Stage Frac Completions. This paper presents an operational overview of first ever deployment of an open-hole completion in a mature gas condensate field located in Potohar region in Pakistan. It had been a norm in this field to hydraulically fracture the two producing zones after cementing the liner. However, often the fold of increase was very marginal despite establishing the hydraulic fracturing design patterns for this field with confidence. In addition, these stimulating operations were frequently compromised because of well and completion design constraints. Execution of open hole completion resulted in gains in the operational efficiency, improved well productivity and had cost benefits which are analyzed against offset wells completed as cased-hole. One interesting observation made is the comparison of un-stimulated base case for the well under discussion against various offset wells located in the field that were hydraulically fractured and how it outshines them with respect to the net production gains. This can be attributed to the characteristic of open-hole completions that provides maximum reservoir contact with minimal formation damage. Based on this experience, it is recommended on integrating and experimenting with relatively new, yet industry established, ideas into field development plans for mature fields with respect to completion design. This can have a lasting impact in extending the plateau production region of the field.

The Ratana Field is a gas condensate field located in the Potwar Basin of Pakistan, discovered in 1990. The field comprises several stacked reservoirs in a thrusted anticlinal fold with two main reservoir compartments, an eastern and a western, which are separated by the main thrusts, but appear to be in pressure continuity through a fracture network. Ratana-2 was the first well drilled in the western compartment which came on production from the Paleocene Patala Formation limestone reservoir and is a major producer in the field. Ratana-2 was subsequently deepened to the Jurassic Datta Formation but because of a stuck drill string in the hole all penetrated reservoirs (Chorgali/Sakesar, Patala, Lockhart and Datta) have been open to flow since November 2009. Well interventions are not therefore possible in Ratana-2 and production and reserves allocation based on limited dynamic data are thus very challenging. Surface-based parameters including water and gas composition analysis, wellhead shut-in pressures, surface production rates and other relevant data were used to perform production and reserves allocation by using a molar equation. The results of the molar equation predictions were cross-checked with the data from nearby well Ratana-4 which is also producing commingled from Paleocene and Jurassic age reservoirs since November 2015. Production logging surveys were acquired twice in over a period of six months and were consistent with the molar equation-derived formation-wise production allocation. Subsequently, the molar equation was used on the available surface data of Ratana-2 for the formation-wise production and reserves allocation and indicates for the first time that the Lockhart Formation as is a contributing reservoir in the Ratana Field and enabling the Lockhart Formation reserves to be booked after seven years of production.

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.

In the wellbore, phase segregation and density changes become significant during gauge pressure measurements. Static pressure surveys capture this change in density, provided the gauge is stationed at different depths in the lower part of the tubing, where this change is most expected. These static pressures are then corrected to datum depth to determine the depletion across the field. Conventionally, a one step pressure correction is used to correct the pressures from the gauge station to datum depth using the wellbore pressure gradient. This approach assumes that the same gradient exists, both in the reservoir and in the wellbore, which is generally not true in the case of gas condensate reservoirs, as well as oil & water producers. This paper presents a two-step pressure correction workflow for gas condensate reservoirs.It proposes to establish a gradient from pressure measurements acquired from lower gauge stations, as segregated fluid density changes even in the liquid column. This is the wellbore gradient. It makes use of PVT parameters to determine the gradient developed by the reservoir fluid, which is independent of the wellbore gradient, to ensure that the correction to datum depth incorporates the actual reservoir conditions. It was observed that two step correction, which makes use of reservoir fluid gradient in 2nd step, provides pressure values comparable with formation testing results in contrast to single step corrected pressures. This paper presents a step by step workflow and emphasizes how important it is to make use of actual reservoir conditions while correcting pressure measurements. Advantages and disadvantages of each correction method are also discussed

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.

Shale gas is a new horizon in Pakistan to meet growing energy demands. Comprehensive data gathering is mandatory for proper evaluation of a shale gas play and to determine feasibility of a prospect. Shale reservoirs require hydraulic fracturing to produce commercially. In Pakistan, stresses are normally high due to plate tectonics. In some cases, the lack of sufficient understanding of stress conditions has led to failures of full hydraulic fracturing operations. Stress testing is a technique used to evaluate formation breakdown pressures and minimum in-situ stresses. Stress profiles can be estimated using openhole log data, however direct in-situ measurement is needed for calibration. Wireline formation testers have been used in the field to measure formation pressures, estimate mobility and obtain good quality downhole samples. One of the advanced applications of the wireline formation testers is to measure insitu stresses in a wellbore to calibrate the mechanical earth model (MEM) and to design a feasible hydraulic fracturing job. Traditional wireline insitu-stress technique has been around for some time now, however the technique suffered from a limited pressure ratings, which was not enough to breakdown the formation. An advanced wireline formation tester module capable of achieving a break down through sleeve fracturing at a very high pressure was used for stress measurement for first time not only in Pakistan but worldwide. The technique involves setting a single packer module across the target shale zone and inflating the packer until the formation breaks down. Once formation break down is achieved, either a straddle packer is set across the target formation and injection is performed for fracture reopening, or another cycle is done with the single packer element to record sleeve reopening pressure. Detailed planning was done by the reservoir and geology departments. Four tests at four different locations were done in the target well where formation break down pressure, closure and fracture re opening pressures were estimated. This information is used for updating a 1D geomechanical earth model for the further use in planning full scale hydraulic fracturing treatment.

Unconventional reservoirs, due to their complexity, are among the greatest challenges to the oil and gas industry. After years of research, shale gas and tight gas reservoirs are now proven to be one of the unconventional reservoirs that are economically viable to fulfill the crucial energy requirements. Due to their low permeability and several other factors, they require advance techniques on both operational and simulation fronts. We performed several different simulations, both numerical and analytical, covering a variety of scenarios to compare shale gas and tight gas production forecasts. Both vertical and horizontal completions were analyzed. For horizontal completions, different hydraulic fracturing stage density was evaluated to identify the best possible production profile for a well and the entire field. The simulations show that Langmuir pressure, volume, rock density, well spacing, completion type, lateral length, and reservoir thickness have a large effect on production forecasts as well as simulations. The simulation results also show the effect of permeability in different cases. The aforementioned are key factors in development plan for a shale gas asset. All the values used for forecasting, both numerical and analytical, are typical for worldwide shales and belong to open source data. They have been selected carefully due to their close resemblance to unconventional reservoirs in Pakistan.

As the demand of natural gas is increasing along with decline in conventional gas resources, the exploitation of unconventional resources has become essential to meet the increasing demand. Shale being unconventional hydrocarbon resource; is very complex in terms of fluid flow and storage mechanisms and require advanced techniques to be modeled correctly. As high investments are involved to develop the resource, therefore representative model is required to decide whether to exploit a shale resource or not, and optimize the development strategy in order to maximize the recovery and profitability. Mostly shale resources are modeled using analytical methods in which best fit model on one well is applied on all other wells of the field to simulate their behavior. However this may not be the case in actual due to heterogeneities in the reservoir. One way to simulate the performance of shale is to use a numerical simulation model in which one can predict the effect of various scenarios on production such as horizontal length, number of stages of frac, etc. In addition it allows to optimize various parameters for the development of field which may not be done through analytical models. In this paper a numerical simulation model is developed for a shale resource. This model is used as a tool for planning and optimizing the development strategy of the resource. The model contains horizontal wells with multi stage fracturing and is validated using well production data of a shale resource. Vertical Lift Performance (VLP) curves are generated from a well modeling software and are incorporated in the simulation model. Horizontal development wells are incorporated to maintain a specific plateau rate. Sensitivity of various parameters such as number of wells, timing of the wells and plateau rate is carried out to study various cases. The results of these cases including plateau rate and period and gas recoveries are presented and the optimum case is selected based on the profitability and maximum recovery. The adopted approach can be used efficiently to evaluate a shale gas prospect to establish its development and appraisal strategy.

Hydraulic fracturing is one of the most effective methods of improving the deliverability of low permeability wells. Hydraulic fracturing in a rich gas condensate field has earned cost benefits by reducing number of infill wells, producing condensate drop out from reservoirs and increasing overall productivity of oil and gas. The target development well was drilled and completed in September 2013 and post completion testing rates as well as pressure build up analysis indicated severe formation damage issues and requirement for hydraulic fracturing. In the same field hydraulic fracturing was carried out earlier in other wells but yielded mixed results. In some of the wells 2-3 times increase in productivity was observed while in some wells, the results were below expectations, despite placing ~100,000 lbs of proppant. In one of the well, formation break down did not occur. Utilizing prior frac experience it was decided to optimize the upcoming frac job but at the same time not to compromise on the frac quality. Extensive pre-job evaluation and planning which included review of available logs and previous frac data, development of 1D Mechanical Earth Model (MEM), frac modeling, implementation of Channel fracturing technique, optimization of fracturing chemical and proppant volumes was done to get maximum benefit of this major well stimulation job. As a result of these efforts frac jobs of the target sandstone reservoirs was completed successfully and the well was put on production in minimum clean-up and post frac testing time. As a result of above effort in planning and optimization of frac job at the target well, significant increase in production was observed which exceeded the operator expectations and raised the confidence level in 1D MEM application for hydraulic frac design (i.e. geomechanics) and the new frac technique by the service company. Based on post frac results, these techniques are being utilized in the upcoming wells in the target field.