Khan, Muhammad Hanif (Independent) | Maqsood, Tahir (Tullow Pakistan) | Jaswal, Tariq Majeed (Pakistan Oilfield Ltd) | Mujahid, Muhammad (Spec energy DMCC) | Malik, M. Suleman (Qatar Petroleum) | Jadoon, Ehtisham Faisal (UEP Pakistan) | Hakeem, Uray Lukman (Qatar Petroleum)
This article investigates the seismic reflection geometries (possible reservoir) of Paleogene of Offshore Indus Basin Pakistan (shelf area) from 2D seismic and make an analogue with the proven carbonate reservoir geometries found in countries such as Canada and Middle East. The 2D seismic data are used to interpret the possible carbonate features and methods to identify them and define its depositional setting on the carbonate platform. The offshore Indus Basin is tectonically a rift and a passive continental margin basin, located in Offshore Pakistan and Northwest India where carbonates were deposited on the shelf and the deep offshore area during early post-rift phase. In the deep offshore area, carbonates were set on volcanic seamounts during the Paleogene age. In Paleogene, the Indian Plate was passing through the equator in the conditions of warmer water with appropriate water salinity, where those conditions were suitable for the growth of organisms responsible to develop reefs in the Offshore Indus area. The available seismic data analysis has indicated the possible presence of different carbonate reefs on the shelf. The seismic data enabled to define the possible carbonate Rimmed shelf depositional model in the area. The aim of this article is to highlight and analogue carbonate seismic geometries, their internal architecture in the Paleogene interval of the Offshore Indus Basin (shelf area) and how to identify them, which may help for further exploration in Offshore Indus Basin.
Siddiqui, Muhammad Arsalan (NED University of Engineering & Technology) | Tariq, Syed Mohammad (NED University of Engineering & Technology) | Haneef, Javed (NED University of Engineering & Technology) | Ali, Syed Imran (NED University of Engineering & Technology) | Manzoor, Abdul Ahad (NED University of Engineering & Technology)
Asphaltene deposition can cause production reduction in oil fields and can create problems in surface/subsurface equipment. The three main factors which affect asphaltene stability in a crude oil are the changes in pressure, temperature and composition. Composition changes occur as the pressure depletes with time and fluid becomes heavier or with gas or chemical injection in reservoir. Any of these changes can destabilizes the asphaltene in crude oil and can cause different operational difficulties, loss in production and increases safety concerns. The objective of this study is to develop a workflow for modeling asphaltene precipitation during pressure depletion and its application to develop mitigation strategy via asphaltene stability maps for a gas condensate field in South Potwar basin, Pakistan
Dahraj, Naeem Ul Hussain (Pakistan Petroleum Limited) | Aziz, Tariq (Pakistan Petroleum Limited) | Asghar, Afnan (Pakistan Petroleum Limited) | Aslam, Adeel (Pakistan Petroleum Limited) | Rashid, Kamran (Pakistan Petroleum Limited) | Hashmi, Shariq (Pakistan Petroleum Limited)
Appraisal and development of tight gas discoveries in Pakistan is a longstanding yet unsettled challenge to local oil and gas E&P industry. Major challenges include but not limited to marginal gas in-place volumes, sustainability of production rates, lengthy cleanup period, significantly higher capital costs due to imported technologies and services, less volume of work, lower competition among the service providers, lower quality gas, lower recovery factors due to tightness and water production, complex reservoir geology and petrophyics. Several such technical discoveries are being made by local and multinational E&P companies time to time but due to one or the other mentioned challenges such discoveries are presumed to be non-commercial and left unexploited. This paper shares a case study of a real tight gas carbonate reservoir located in Middle Indus Basin of Pakistan which may help the E&P professionals’ kick-off the thought process to understand such discoveries and adopt new strategies to bring them on production.
The well Naushahro Feroze X-1 (NF X-1) was drilled as an exploratory well to target Chiltan Carbonate Reservoir in the Naushahro Feroz block in Sindh, Pakistan. A tight gas discovery was made in the Chiltan formation based on the well logs and testing results. It was concluded as naturally fractured carbonate reservoir (NFR) and classified as Type-II NFR, Nelson (2001)1 i.e., mainly fractures provide essential flow capacity. Reservoir evaluation indicated reservoir is over pressured and its permeability is in micro Darcies. Subsequent horizontal appraisal well i.e., NF Hor-1(RE) drilled with a lateral section of ~1300 meters. The well was completed with an open-hole-multistage string and ten stages were selectively acid stimulated, acid fractured and hydraulically fractured to establish the sustainable commercial gas rates. The performance of both the exploration and appraisal wells exhibited typical production behavior of tight gas wells with continuous decline in gas rate and wellhead flowing pressures, however, the appraisal well proved to be better in terms of production due to better drilling, completion and stimulation strategy.
Sustainable production rate in the appraisal well could not be established due to extremely tight nature of the matrix and water production from the deeper intervals. Surface separator multirate test was performed followed by an extended buildup period and the surface data was recorded. The data was then used to understand the reservoir behavior on short term and long-term basis using various analytical and numerical analysis techniques. A 3D Black Oil dual porosity model was developed for reservoir simulation and understanding the reservoir behavior. In the static model, the natural fractures were characterized using the seismic attributes across the Chiltan formation. The model was then initialized, and history matched using the available rock and fluid properties, multirate test and extended buildup data. After completing the analysis, an understanding was developed about the production strategies and well wise range of gas recoveries in such tight gas discoveries which has been shared in this paper.
The concept of unitization albeit has been in its infancy under the existing upstream exploration & production oil & gas legal regime in Pakistan, even though there are many straddling reservoirs which continue to be in communication. Therefore, the need to develop a comprehensive legal & regulatory framework that covers all aspects of unitization of straddling reservoirs and closing all pending unitization issues is the dire need of the hour. This is not only critical from the Governments' perspective but is important for the companies subject to unitization to effectively monetize their returns on investment.
The paper concludes that in the presence of a strong regulatory framework comprehensively addressing unitization of straddling reservoirs, upstream companies would be forced to unitize, either by incentives or by compulsion while the regulator shall continue to supervise their work programs regarding field development. The paper attempts to provide creative guidance for setting up a comprehensive legal/regulatory framework addressing unitization.
Unitization is the process of joint development of a hydrocarbon reservoir which extends across block boundaries of two or more production licenses (leases in Pakistan) operated by different lease groups (unincorporated joint ventures in Pakistan). Under unitization, each lease group agrees that the straddled field is aggregated as a “unit”, in which each lease group is entitled a percentage interest called “Tract Participation”. Tract participation defines the share of hydrocarbon volumes and cost of each lease group in the common pool. The percentage interest of each leaseholder (company) in the “Unit” is called its “Unit Interest”, which is based on working interest of leaseholder in the lease group and its tract participation.
The objectives of unitization include but are not limited to preventing waste (economic, underground, surface & environmental) by assuring efficient, orderly, and environmentally responsible development and by facilitating joint operations to maximize efficient hydrocarbon recovery. It also provides a means to fairly allocate hydrocarbon reserves and costs among lease groups and resolving disputes that may arise. The concept of unitization is elaborated in Fig-1.
Mehmood, Amer (Pakistan Petroleum Limited) | Ali, Dost (Pakistan Petroleum Limited) | Mallah, Sohail Ahmed (Pakistan Petroleum Limited) | Rashid, Kamran (Pakistan Petroleum Limited) | Mhiri, Adnene (Schlumberger) | Ramondenc, Pierre (Schlumberger) | Khalid, Aizaz (Schlumberger) | Briones, Victor (Schlumberger) | Khan, Rao Shafin Ali (Schlumberger)
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.
Farid, Syed Munib Ullah (Pakistan Petroleum Limited ) | Ahmed, Hassaan (Pakistan Petroleum Limited ) | Mallah, Sohail Ahmed (Pakistan Petroleum Limited ) | Khanam, Mehwish (Pakistan Petroleum Limited ) | Dhawan, Sandeep (WellPerform ApS )
HPHT well environments present design & operational challenges that could potentially translate into well failure with high consequences. Several risk elements can combine into a complex hazard causing serious threat to well design & integrity. Risk elements could be complex downhole environment, material deration, material incompatibility with the completion/packer fluids and other treatment fluids, metallurgy imbalances etc. This case study presents early life production tubing integrity failure highlighting gaps and suggestions to adopt an integrated risk mitigation approach.
A 5,700 m TVD keeper HPHT exploratory well was drilled in north of Pakistan with reservoir pressure, temperature exceeding 10,000 psi and 320oF respectively. Matrix acidizing was required to remove near wellbore damage in the targeted carbonate reservoir. Initial kick start stimulation efforts resulted in tubing-annulus communication indicating compromised CRA super 13CR completion string integrity. Workover followed wherein another early life completion string failure occurred. Consequently, comprehensive analysis was carried out to determine failure root causes using a systematic fault tree analysis approach.
Failure investigation consisted of two broad scopes: a) Scrutinize well design against established industry standards and best practices for HPHT wells and; b) Completion string material metallurgy tests to evaluate compatibilities with exposed well & treatment fluids, bottom hole environment and assessment of all possible risk scenarios that by itself or in combination with other risks could cause material failure. Further, detailed study work included describing bottom hole environment comprehensively, various types of corrosion risk assessments including evaluation of environment assisted cracking risks, acid inhibitor efficiency evaluation, completion/packer fluid selection, fluid compatibility assessment and fluid additives degradation at high temperatures. Mill manufacturing processes, susceptibility of CRA material passive layer because of austenite percentage were also looked-into. Based on systematic approach and extensive in-depth analysis, key observations were drawn. These observations were further investigated with material testing and possible root cause failure risk factors were arrived at. Conclusions were drawn highlighting primary and secondary failure root causes. A new basis of design and qualification protocols was proposed to mitigate various risks to ALARP.
Unavailability of gas transmission network near a hydrocarbon discovery leading to high pipeline infrastructure development cost and can cause delays in production or remain stranded, for several small gas reservoirs. This study explores the avenues of exploiting small and stranded gas reservoirs, through virtual gas pipeline by compressing the gas and transporting it through bulk transportation modules, primarily for use at Captive Power Plants, Processing Industries and CNG Stations. Virtual Pipeline (VP) system is being effectively used in many parts of the world for production from low volume stranded gas reservoirs. In Pakistan, presently, three stranded gas reservoirs are producing about 4 MMscfd gas through VP system in the Northern region of the country with the first such system being operative since 2010. Whereas, several opportunities exist in the Southern region of the country, as well, to add production from stranded gas reservoirs to national energy network through VP system. An economic model has been developed for the operators to assess the viability of VP vis a vis gas transmission pipeline and bring low volume stranded gas into the system. Results of economic model indicate that for small stranded discoveries with uncertainties in connected hydrocarbon volumes, production through VP offers better NPV than the conventional pipelines. Based on economic model, the concept of VP was implemented at one of PPL’s well, which commenced production on 27 October 2017, and currently producing 1.4 MMscfd gas and 110 bbl/d of condensate. Based on the collected data, if higher hydrocarbon volumes in place are estimated, the feasibility of laying feeder line to a nearest processing facility may be re-evaluated to compare with the currently utilized VP system.
The transportation of natural gas from hydrocarbon producing fields to consumption areas require a dedicated gas transmission pipeline network. With the advent of industrialization and urbanization, increase in gas prices has made it economically feasible to bring several smaller and remote gas well into production by connecting to the gas transmission network in the vicinity. Unavailability of gas transmission network in the vicinity of a hydrocarbon discovery leading to high pipeline infrastructure development cost and can cause delays in production from several stranded small gas reservoirs.
Inam, Sahir (KUFPEC Pakistan) | Shaukat, Ch Bilal (KUFPEC Pakistan) | Haider, Syed Afraz (KUFPEC Pakistan) | Latif, Muhammad Khalid (KUFPEC Pakistan) | Ali, Abid (KUFPEC Pakistan) | Abbas, Asad (MOL Hungary)
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.
Wells in low to moderate permeability or wells having hydrocarbon in-place that cannot be produced naturally are candidates of Hydraulic Fracturing. Hydraulic Fracking is one of the stimulation techniques being applied to such wells since 1950’s however, technology has increased tremendously in the recent past. This technique is the major contributor towards commercial success in Shale and Tight
Reservoirs. Key components of any hydraulic frac jobs are a). Products (Frac. Fluid, Proppant, Water, Acid, Guar etc.) and b). Services (Equipment & Personnel). Based on the historical job cost, approximately 70% of the total frac cost reflects Product part.
As per EIA assessment 2015, Pakistan stands 9th in the world in terms of total Shale Oil Resources with estimated Technically Recoverable Resources of 9 Billion Barrels oil and Risked Technically Recoverable Gas Resources are estimated as 105 TCF. Pakistan consumes 100% of its natural gas production and remaining shortfall is being managed through LNG import which requires high foreign exchange. In order to overcome current energy shortfall, Shale Oil/ Gas can be future growth of Pakistan.
Mehmood, Amer (Pakistan Petroleum Limited) | Ali, Dost (Pakistan Petroleum Limited) | Mallah, Sohail Ahmed (Pakistan Petroleum Limited) | Rashid, Kamran (Pakistan Petroleum Limited) | Khan, Rao Shafin Ali (Schlumberger) | Khalid, Aizaz (Schlumberger) | Altaf, Omair (Schlumberger) | Jan, Usman Ahmed (Schlumberger) | Qadir, Waqas (Schlumberger)
Lack of real-time downhole data for accurate depth correlation and precise control of pressure actuated tools, often result in inefficient coiled tubing (CT) interventions. Surface readouts have been conventionally used to infer downhole conditions during CT operations; however, the presence of the above-mentioned unknowns along with dynamic wellbore conditions make surface measurements an insufficient approach for knowledge of the actual downhole conditions. This study describes how access to real-time downhole measurements was gained by using CT fiber-optic downhole telemetry and how its implementation contributed to address operational challenges encountered during CT abrasive perforating interventions in Pakistan.
The application of CT equipped with fiber optics and instrumented bottom hole assembly (BHA) to vertical wells in onshore Pakistan required specific designs and new processes for preparing, executing, and evaluating well interventions. Planning and design considerations included selecting the BHA and performing pre-job quality checks of the optic fiber. This novel approach leveraging fiber optic telemetry relies on fibers inside an inconel tube within a CT string, and a downhole BHA that includes pressure and temperature gauges and a casing collar locator (CCL). The BHA acquires real-time data providing quantitative feedback of downhole wellbore conditions during the interventions, which enables accurate placement and controlled actuation of the hydraulic abrasive perforating gun.
Depth accuracy for tool positioning, and differential pressure across the gun nozzles were of utmost importance for suitable abrasive perforating interventions. Downhole pressure gauges monitored the annulus between CT and production liner, and CT internal pressures at all times, helping to keep the differential pressure within the 2200 – 2600 psi for optimum abrasive perforating. The CCL data was utilized to correlate depth for precise perforations placement. Multiple wells were perforated using the combination of CT fiber-optic telemetry and abrasive perforating. The BHA delivered real-time downhole data, which helped to understand the changing wellbore conditions. Implementation of this new methodology increased the operator’s confidence with abrasive perforating, as previously very little downhole data was available to make informed decisions to optimize such interventions and ensure effective perforating at target depth. This study introduces a novel perforating technique in Pakistan. The use of CT fiber-optic downhole telemetry is not limited to perforating, and the BHA can also acquire gamma ray, tension and compression forces, torque, and even flow data. Such systems can have a significant impact in overcoming intervention challenges faced today in Pakistan.
Shahid, M. Hasan (Ocean Pakistan Limited) | Akhtar, M. Saeed (Ocean Pakistan Limited) | Kumar, Sharven (Ocean Pakistan Limited) | Shakeel, M. (Ocean Pakistan Limited) | Shakeel, Mariam (Ocean Pakistan Limited) | Tanveer, Atif (Ocean Pakistan Limited)
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.