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.

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.

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.

The numerous advantages and benefits of Multiphase Flow Meters (MPFM) experienced globally by major oil & gas operating companies were studied by and have driven OGDCL for using MPFM for well testing their challenging fields. During the past year, OGDCL has installed, field-tested and deployed their first multiphase flow meter at Nashpa oil field. The objective of the field-testing program of the MPFM was to establish the meter ability to accurately measure the three production phases (oil, water, and gas) and to determine meter reliability in a field environment. During trial testing, the MPFM flow rates were compared to reference conventional test separators and storage tanks within the allowable accuracy bands. Both the meter accuracy and operational reliability were satisfactory to OGDCL acceptance criteria. The application of MPFMs in OGDCL production operations will provide continuous on-line well production monitoring and eliminate large conventional test separators and test lines. As a result, tremendous economic savings would be realized due to a significant reduction in capital and operating expenditures associated with well-testing activities. The MPFM covers a wide range of multiphase applications at several different oil and gas-condensate fields. This technically developed, compact non-radioactive MPFM is targeted for testing wells at remote onshore fields and for future potential unmanned offshore platforms, where weight and space are major concerns. Currently, in OGDCL the combination of MPFM technology with a well-designed test plan is leading to the optimization of the well performance Continuous well-test data being obtained from MPFM is leading to accurate production allocation and better reservoir management. Thus, the introduction of online Multi-phase Flow Metering (MPFM) technology presents a reliable alternative to conventional test separators for well testing and flow measurement in Pakistan's oil and gas industry. This overcomes the limitation of conventional well testing means and technologies to operate with higher gas volume fraction, varying water cut and changing dynamics of the multi-phase flow. This paper discusses in detail the success story of multiphase flow meter (MPFM) and its application program in OGDCL. The paper also presents an overview of MPFM technology. This will add to the existing SPE literature a focused technical paper describing the MPFM installation and application experience in OGDCL Pakistan that can be used as a reference by other operating companies, academic personnel, R&D organizations and New Technology promoters in the country.

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.

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.

Leak identification across well completions is a crucial operation in the oil and gas industry. A failure of well barriers can result in uncontrolled release of hydrocarbons and pose major risks to personnel and environment. Downhole gauges are widely used to provide pinpoint measurements of pressure and temperature across the completion; however, those measurements alone are insufficient to properly diagnose single or multiple well integrity issues. Alternative well intervention methods are needed to qualitatively estimate the location and number of potential leaks. For the past decade, distributed temperature sensing (DTS) has been used in wellbore completions and surface pipelines with preinstalled fiber optic lines to identify leaks by monitoring and processing temperature profiles across the length of the installation. The proposed methodology makes use of a similar principle, relying on coiled tubing (CT) to deploy the fiber optics and conduct DTS integrity assessment in wells completed without fiber optic lines. This use of fiber optics inside a CT pipe also provides simultaneous real-time downhole measurements, which include CT internal and annulus pressures, and casing collar locator (CCL), for precise depth control and accurate correlation of well parameters. In the south of Pakistan, the tubing-casing annulus pressure of a high-temperature gas well increased to near flowing wellhead pressure at the tubing, giving a clear indication that at least one of the completion components had failed, resulting in flow of hydrocarbons to the annulus. Yet, the high wellbore temperature limited conveyance of conventional logging tools to assess downhole completion integrity. A thorough analysis of well hydraulics was first conducted to gather the possible options to identify the leak using DTS. This enabled the determination of a workflow aiming to create enough differential pressure to generate particular temperature disturbance. CT equipped with fiber optics was run and stationed across the complete wellbore length, and DTS data were acquired for approximately twelve hours under changing well conditions, including shut-in and flowing periods. The acquired temperature information for each phase, along with pressure information, helped to narrow down the location of possible leak points. This methodology enabled the identification of a single, major leak point located at an expansion joint in the completion. The operator was able to riglessly set an annular plug to restore integrity, thus saving significant workover cost and time.

Exposure of production annulus with formation fluids due to tubing-casing communication is unfavorable scenario throughout well's life cycle. The communication paths are always susceptible to aggravate with the passage of time, eventually resulting in complete loss of well integrity due to failure of one of the integral well barriers and potentially causing major risk and hazards to environment and personnel. Accurate and most efficient actions are therefore required on war-foot basis to restore lost integrity. DST of an exploratory well in South Pakistan revealed the corrosiveness of reservoir fluid (26 % CO2), therefore, completed with chrome material. Well remained shut-in due to plant capacity constraints. Soon after well commissioning, pressurized annulus was reported. Initial investigation depicted hydrocarbons in annulus, however, Distributed Temperature Sensing (DTS) was later used to accurately locate the leak path. Conventional remedial options including tubing patch and work-over were ruled out due to extreme reservoir parameters and associated high cost as well as production curtailment. Placement of Resin-Based Isolation Plug (RBIP) in annulus was found to be the most feasible option to restore well integrity. Coiled tubing conveyed DTS was carried out in shut-in and flowing conditions that confirmed depth of leak path in completion string. Main reason of implementing this diagnostic technique was the unavailability of conventional logging tools compatible with high temperatures. DTS was run in conjunction with correlating tool (CCL) for precise depth determination with respect to completion jewelry. After exploring pros and cons of conventional remedial techniques, treatment through annulus was the only remedial option left to block the leakage path in completion string therefore, placement of RBIP on top of leak point was planned. This plug, once solidifies, restricts tubing movement due to thermal effects when exposed to production loads. Therefore, extensive stress analysis was essential to evaluate the integrity of anchored completion due to plug under various production loads throughout the well's lifecycle. With all possible risks critically assessed, RBIP along with bridging spacers was successfully poured in annulus during rig less operation. Well was kept in flowing conditions towards plant to avoid production curtailment throughout the operations. Currently, well is flowing, maintaining the necessary feed at plant and fulfilling country's gas demands with well integrity intact. Tubing-Casing communication and pressurized annulus has become common problem and plays significant role in maintaining the reputation and progress of E&P companies. Conventional methods are readily available to rectify such problems however, there are scenarios where wellbore conditions / parameters and economic feasibility may restrain their implementation. RBIP is a new technique in restoring well integrity through annulus and is successfully implemented for the first time not only in Pakistan Petroleum Limited (PPL) but in Pakistan.

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.

For a well production optimization and cost per barrel of oil reduction, it is very essential to have an accurate measurement of well flowing bottom-hole pressure (FBHP) available all the time during the life of the well. It is a common practice follow in the oil and gas industry to run bottom-hole pressure gauges to record FBHP. However, interfering a producing well is an expensive and time-consuming task, involved with production disruptions and safety risks. To address these concerns, numerous mechanistic and empirical models were formulated to predict FBHP. Among these a large number of models were developed under small laboratory scale conditions and are, ultimately, inaccurate when up-scaled to field conditions. This study presents an intelligent solution by the development of an empirical model to quantify FBHP for a vertical well. The new model is based on the surface production data such as tubing perforation depth, flow rate of oil, flow rate of gas, flow rate of water, API gravity of oil, tubing string internal diameter, well bottom-hole temperature, wellhead surface temperature, and wellhead pressure. The data used to train the proposed empirical model collected from the published sources, which covered practically reasonable values. The proposed model is also validated by testing against new dataset, and the results were then compared statistically with the other methods used in petroleum industry. The results show that the proposed empirical model considerably outperforms reviewed models and delivers the prediction of FBHP with high accuracy. The novelty of the proposed empirical model is that it depends only on the surface production which makes the prediction of FBHP in a real time. The proposed model is accurate and can serve as a handy tool for the production engineers to forecast the FBHP in a real time.

Conventional production logging with electric line is sometimes challenged by the presence of mechanical restrictions in the wellbore. The fragility of production logging tools also impedes the use of electric-line coiled tubing (CT) with the risk of damaging tools across sections with little clearance. This study showcases conclusive flow profiling using distributed temperature sensing (DTS) via fiber optics deployed with CT in a gas condensate well where wellbore access prevented the use of logging tools. Flow profiling via DTS has been used globally in completions where fiber optic lines are permanently installed. Interpretation of those logs usually leverages months of acquired data to invert temperature information and obtain the evolution of flow distribution over time. The proposed methodology instead relies on hours of DTS acquisition through the temporary deployment of fiber optics with CT. A comprehensive sensitivity analysis on key unknown parameters is then performed using a fit-for-purpose thermal-flow simulator to match simulated and acquired temperature profiles, leading to a flow distribution of gas, condensate, and oil in the wellbore. Before the intervention, an evaluation study was run using a flow-thermal simulator to evaluate the expected sensitivity of wellbore temperature to poorly characterized downhole parameters, such as permeability, pressure, or skin. This allows determining the downhole conditions under which DTS is able to detect flow contribution for a specific candidate. During the operation, the CT equipped with fiber optics was stationed across production zones for a total of 06 hours. The data was processed and fed back to the simulator along with reservoir, well data, and surface rates. To further constrain data processing, pressure surveys were acquired during the CT run using a downhole gauge, both during flow and shut-in periods. Unknown reservoir properties were sensitized during data interpretation to obtain a match between acquired DTS profiles and simulated wellbore temperature evolution, which, in turn, yielded an associated flow distribution. The matching exercise being an open-ended mathematical problem, several scenarios were considered, and their results checked against further production characterization of the wellbore and the field. The proposed case study illustrates how this methodology enabled logging in a mechanically-restricted zone and helped determining that the top interval was not contributing to flow. Flow profiling can be performed using a wide range of complementary logging tools, but the evolution of completions over the past few years is increasingly introducing mechanical restrictions that prevent the conveyance of such tools altogether. This study demonstrates that DTS can be a viable alternative for assessing zonal flow contributions. It also discusses the conditions under which this methodology is achievable.

Field production testing is commonly done for the purposes of monitoring field production, observing productivity trends, determining fiscal allocation and field contributions. In Pakistan, production tests are used to measure flow rates to update reservoir parameters, monitor field decline, and to allocate portions of total central facility production to specific fields and wells. A major portion of fields in Pakistan flow from wet gas or gas condensate reservoirs, and these are typically the most challenging to accurately test. Conventional test separators have long been used for well testing and flow metering. They physically separate the phases and the individual phases are metered using dedicated methods, that have been fine-tuned over decades. Multiple tanks and pumps are used in conjunction with the separators to complete the well test package and handle separated fluids. Multiphase flowmeters (MPFMs), however, are a much more compact technology with significant operational benefits and have matured and gained acceptance over the past two decades. They continuously measure three-phase flow rates without requiring separation. Many MPFMs have no moving parts, making them more mechanically reliable. The capability for continuous monitoring enables quick, well-informed decisions to be made on well performance. MPFMs bring distinct advantages over conventional well testing equipment for the purposes of production testing. The unseparated stream can be re-injected into the production line, and there is zero impact on the production plant operations. Use of MPFMs results in faster tests because of quicker parameter stability, wider dynamic range and shorter rig up times. MPFM setups also have smaller, lighter physical footprints, which do not require large pressure-energized vessels, so associated health and safety risks are lower. Often, the costs to the operating company are lower because of reduced equipment and personnel requirements. In this paper, we present a study where an advanced dual-energy gamma venturi MPFM was used to test multiple wells in multiple complex condensate gas fields. We discuss the performance of the MPFM against a given set of metrological expectations, and provide an analysis of a comparison test done inline with a conventional test separator. Finally, based on these analyses, we present the advantages and challenges of using MPFMs for production testing and surveys in different fields in Pakistan.

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

In stacked reservoirs with limited accumulation, it's a practice to produce reservoirs commingled, but there are always challenges in the allocation of production and estimation of in-place for such reservoirs. This paper presents an analytical approach using Material Balance (MBAL TM ) reservoir allocation tool for allocating production and inplace estimates on individual basis for such reservoirs. MBAL TM allocation tool, unlike the traditional allocation approach of using product of (kh), works in a twostep process; (i) Defining inflow for an individual well at each time step and (ii) Setting up Material Balance model that accounts for the rate of depletion which will correct inflows at each time step. This study highlights the approach of MBal reservoir allocation tool on a gas field with significant water production, producing from two different units of Sand-1. In this regard, determination of GIIP and aquifer strength was a great challenge. Production logging data was acquired which showed significant gas and water production from bottom unit of Sand-1. Bottom hole flowing pressure (BHFP) and individual zonal contribution in terms of rate acquired from production logging data was used as a history matching parameter. Regression of darcy and non-darcy parameters aids in matching production logging results, which in turn develops inflow performance for an individual layer at each time step. Apart from this, measured static bottom-hole pressure (SBHP) was used in order to determine the impact of depletion at each time step, further supplementing development of inflow performance. Finally, production data on individual reservoir level was determined based on production logging data calibration, supplemented by static pressures matched using gas and aquifer volume. Matched results estimated Sand-1 Unit-1 GIIP to be around 74 Bcf with depletion drive trend, whereas bottom unit exhibited weak to moderate water drive behavior with GIIP of around 19 Bcf. Based on these results, bottom unit wasn't isolated and left open to drain remaining potential, thereby outrunning the aquifer in order to maximize its recovery. In scenarios, where we are producing from multiple reservoirs, production from reservoir with inferior quality is masked by prolific reservoir, whereas on other side reservoirs with significant water production masks reservoir with water free production. It is necessary to plan development and depletion strategies for such reservoirs, but prior that price in terms of potential needs to be addressed. Using this technique, one can overcome challenges in multiple stacked reservoirs.

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.

One of the main challenges in a water drive gas reservoir is to track fluid movement as water breakthroughs occur frequently with depletion. The understanding becomes more challenging when the structure contains seismic/sub-seismic faults with the associated drive mechanism being edge water. Moreover, surveillance options are also limited for such reservoirs if they are producing through short string of a dual completion. Dual string completion is a cost-efficient technique as multiple reservoirs can be completed in a single wellbore. However, surveillance / logging cannot be performed across perforation intervals of upper reservoir due to operational concerns. As a result, the short string production can only be surveyed through the long string with the help of tools which have deep scanning radius extending beyond tubing and casing into the formation. One example of these advanced tools is Spectral Noise Logging (SNL) combined with High Precision Temperature (HPT) logging which have been used worldwide for such applications. This paper presents SNL-HPT results of two dual string wells completed in Eocene age carbonate reservoir. A total of nine wells are producing from the reservoir and the Gas water contact (GWC) was not encountered in any of the wells. Selected wells are located on either side of the structure with Well A producing 1.0 MMscfd gas and 1300 bbls/d water while Well B is producing 2.0 MMscfd gas and 800 bbls/d water. The reason of high water production from both wells was initially attributed to the presence of a high permeability streak in lower part of the reservoir and/or possibility of channeling behind casing. However, results of the SNL-HPT in both wells indicate signatures of fault or fracture flow. The major water production is coming from the middle and lower part of reservoir. Based on these results, the trajectory of one development well was optimized. The perforation interval of another well was also decided in accordance with the SNL-HPT findings, which resulted in water-free gas production. Quantification of reservoir flow profile in short string of dual completion well is possible through noise and temperature logging. This information would help in deciding appropriate workover strategy in existing wells and completion design of new development wells.

The case study presents an integrated workflow with the focus on the thermal analysis of the completion string, wellhead and surface network. The research outcome are the temperature profiles under various production scenarios that are used as the justification of the installation of wellhead cooler on an exploratory well of lower Indus basin in Pakistan. The advent of deep well drilling in high temperature and high pressure formations posed serious concerns for drilling, completion and facility design engineers as these are one of the key parameters for material and fluid selection for completion string. The uncertainty in these parameters throughout the operational life of the well may cause an over-designed or underdesigned well completion and production facility. The equation gets further complex if the inherent uncertainty in type and quantity of produced fluids is neglected or underestimated. To overcome these challenges, a workflow considering the downhole completion considerations and wellhead treatment of produced fluid; in consideration of wellhead temperature; is proposed. This paper presents reservoir and completion design considerations of an exploratory well in lower indus basin. Effect of various production scenarios on temperature profile are considered based on the possible drive mechanisms of hydrocarbon production. The analysis includes the development of completion string model for well S-X1 and coupling the same with the hydrocarbon processing facility through surface network. The model is calibrated using history matching of temperature profile using the production data and sensitivity analysis of various parameters was performed. Based on the simulation results, it was observed that the proposed workflow using industry standard commercial software for thermal analysis is a more realistic approach for temperature prediction using production profiles. The proposed workflow will serve as the guidelines for wellhead and surface facility design under various expected production scenarios.

Formation permeability (k) and fracture half-length (X f ) determination provides the ability to economically optimize well and fracture spacing. For wellbores completed in the gas-condensate and oil window (producing below saturation pressure) two-phase flow occurs from the fracture face increasing in distance until it reaches the no flow boundary from the adjacent fracture face along a horizontal wellbore. Thereafter the flow becomes boundary dominated. It becomes challenging to precisely pick the end of linear flow time and the start of boundary dominated flow regime due to long transient region in shales (low permeability nature). End of linear flow time is used to calculate both the permeability and original gas in place (OGIP) using production data. Existing practices in the literature suggest to pick the end of linear flow time implicitly from the plot of reciprocal rate vs cumulative production. The deviation on the line is termed as typically the time at which linear flow has ended. However, considering the lengthy transition regions in shales, this involves a great deal of error as the end of linear flow time is not calculated mathematically but picked on the analyst's eyeballing practices. Thus, a small mispick of end of linear flow time could result in substantially misleading permeability and OGIP. The primary work presented in this paper resolves the selection of end of linear flow time by proposing a technique which involves production data analysis equations and statistical methods along with graphical techniques to calculate and rightly pick the end of linear flow time. Since gas condensate ratio (GCR) remains constant during the linear flow regime, our methodology also involves reverification of the end of linear flow time. This is done by picking the increase in GCR which happens at the end of linear flow on the plot of cumulative production versus the GCR. While the procedure involved laboratory fluids, special core analysis, and numerical simulation, the methodology lends to a wide range of liquid-rich reservoirs where linear flow analysis is appropriate.