Ali, Hamza (Schlumberger) | Shah, Abdur Rahman (Schlumberger) | Akram, Agha Hassan (Schlumberger) | Khan, Waqar Ali (Schlumberger) | Siddiqui, Fareed Iqbal (Pakistan Petroleum Limited) | Waheed, Abdul (Pakistan Petroleum Limited) | Ahmed, Faizan (Pakistan Petroleum Limited)
A recent study addressed the modelling challenges of Alpha* gas condensate field. Alpha gas condensate field has a gas in-place of about 1 TCF, and both condensate and black oil production in addition. The field has been producing from two reservoirs SI and DI, for the past 26 years. Alpha field is subdivided into two segments called the Central Area and the Northern Area which are separated by a fault as shown in Figure 2. * Not its real name. One of the most unusual features of Alpha field are the'phase switch wells'.
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.
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.
Yousuf, Arif (Sprint Oil & Gas Services) | Temuri, Saqib Jah (Sprint Oil & Gas Services) | Raza, Mustansar (Sprint Oil & Gas Services) | Dar, Afnan Ahmed (Sprint Oil & Gas Services) | Siddiqi, Sarmad S. (Pakistan Petroleum Limited) | Hammad, Muhammad (Pakistan Petroleum Limited) | Ahmed, Muneeb (Pakistan Petroleum Limited)
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.
In matrix acidizing of carbonate formations, acids are commonly used to increase matrix productivity by creating wormholes (new flowing channels) that connect the formation to the wellbore. Hydrochloric (HCl), formic or acetic acid, or mixtures of these acids are widely used in matrix acidizing treatments of carbonate reservoirs. However, in present time, a new set of chemical stimulation fluid called Chelating Agent (CA) is introduced in industry to treat limestone and sandstone formations even at high temperature. Chelating agent is widely acclaimed over the conventional acids due to its physical and chemical prowess.
The main challenge using HCl in stimulating carbonate formation is face dissolution caused by the rapid reaction of HCl with formation minerals. This challenge aggravates when temperature goes above 250 deg F where wormhole propagation is minimum and wormhole widening is generally observed.
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.
Bari, Abdul (Schlumberger Seaco Inc.) | Dar, Usman (Schlumberger Seaco Inc.) | Zubair, Talha (Schlumberger Seaco Inc.) | Sarili, Mahmut (Schlumberger Seaco Inc.) | Siddiqi, Sarmad S. (Pakistan Petroleum Limited) | Hammad, Muhammad (Pakistan Petroleum Limited) | Jalil, Talha (Pakistan Petroleum Limited) | Siddiqui, Suhail Ahmed (Pakistan Petroleum Limited)
Over the years, wireline formation testers have been frequently used for evaluation of near wellbore reservoir characteristics using mini-DST technique. Its primary applications are especially in case of tight or laminated layers where conventional testing approach is time consumingin terms of rig time and associated cost. Such evaluation helps client in optimizing their completion strategies. One such successful application of mini DST technique has been in Kandhkot field; which is sub divided into three domes having three reservoirs Sui Main Limestone (SML), Sui Upper Limestone (SUL) and Habib Rahi Limestone (HRL). Formation evaluation which included core analysis and open hole logs; was carried out in surrounding wells encountering SUL and it showed relatively less porosity and permeability in West dome (Ф=8-12% and K=0.1–1.68mD). Testing on two wells confirmed gas presence but its potential could not be established due to low rates. To address this challenge, wireline formation testing technique with straddle packers was opted in a well KDT X, encountering SUL formation. By successful utilization of Mini DST, Operator managed to evaluate critical reservoir parameters for characterization of all individual layers, which helped in better reserves estimates and reservoir modeling.
Wireline formation testing has been in use for several decades now. Advancements in wireline formation testers have led to an effective reservoir evaluation through its various answer products. Reliable pressure and mobility measurements, fluid gradients and contacts, downhole fluid analysis and PVT sampling, vertical interference testing and reservoir characterization are few to count.
Complex lithology, naturally fractured carbonates, multiple reservoir sections and various reservoir heterogeneities present significant challenges for formation evaluation. Generally, it takes several days to weeks to test multiple formations separately; which can lead to increase in associated cost. One of the efficient approaches in such situations is to utilize wireline formation tester tools which can provide an opportunity to test multiple formations during same run. For downhole testing of laminated, tight or fractured formations, a straddle packer (commonly known as dual packer module) is used to isolate the interval of interest; followed by series of controlled drawdowns and buildups to perform pressure transient analysis, known as Interval Pressure Transient Testing (IPTT).
Khalid, Ali (Weatherford International Ltd) | Ashraf, Qasim (Weatherford International Ltd) | Luqman, Khurram (Weatherford International Ltd) | Moussa, Ayoub Hadji (Weatherford International Ltd) | Nabi, Agha Ghulam (Pakistan Petroleum Limited) | Baig, Umair (Pakistan Petroleum Limited) | Mahmood, Amer (Pakistan Petroleum Limited)
Carbonate platforms are one of the most common reservoirs on earth, and as such are one of the most frequently explored.
Sulaiman fold belt in Pakistan is known to contain multiple hydrocarbon bearing carbonate formations. One such formation is the Sui Main Limestone formation. The formation when first discovered was known to contain over 9.5 Tcf of gas in Sui field, and up to 5.0 Tcf of gas in the neighboring Zin field. Over the years due to extensive field development and production, the Sui Main Limestone reservoir has been driven to depletion. Operators are now looking to explore deeper horizons in the same fields.
The challenge in deeper exploration of the subject fields is now a depleted pressure of about 2.1 ppg EMW of the Sui Main Limestone formation. In addition to the low pressure, the SML formation is highly fractured in nature. These two factors resulted in massive circulation losses when an attempt to drill a well was made through the approximately 650 m width of the SML formation. To cure losses, operators resorted to heavy LCM pills, and numerous cement plugs. Losses in the hydrocarbon bearing SML formation also led to well control and stuck pipe events on multiple occasions. Successful drilling through the whole width of SML formation would sometimes take up to almost 3 months. Drilling time and lost circulation materials thus generated excessive well costs.
The operator sought a solution which would eliminate circulation losses in the SML formation, and cut down drilling time substantially. An underbalanced system was first considered for achieving these objectives but as the SML formation bore sour gas and excessive equipment would be required for a safe underbalanced operation, the option was ruled out. A nearbalanced nitrified foam system was thus designed to be able to drill the SML formation delivering the same benefits of an underbalanced operation without its perils.
By applying a nearbalanced nitrified drilling technique, operators in the subject fields were able to cut down the drilling time to about 3-5 days, achieve a substantial increase in drilling performance, and practically reduce the NPT to 0.
This paper studies the planning & design of a nearbalanced nitrified foam system for two different wells with hole sections of size 17", and 8-1/2". The paper also discusses the equipment selection, the wellsite execution, and the results achieved by applying nearbalanced nitrified foam drilling in the subject fields.
One of the most challenging part of managing a Gas-Condensate reservoir is to reduce Condensate Banking and its damaging impacts on the overall recovery. Several techniques have been applied in the past to overcome this problem such as pressure maintenance by Gas Injection (i.e. Lean gas, CO2 or N2), Water-Alternating-Gas (WAG) or chemical injection etc. However, none of these techniques could easily be initiated on a mature Gas-Condensate Field owing to the large upfront CAPEX and technical limitations. This study presents a strategy on such a mature Gas condensate reservoir, to target the Condensate banks and improve the overall condensate recovery.
This study has been based on a field currently producing from the Potwar basin of Pakistan. The current pressure of the field is around 2500 psi - significantly lower than the Initial Reservoir Pressure (5200 psi) and Dew point (4950 psi). The PVT reports are showing that the reservoir has already passed the region of Maximum Liquid Drop out (MLDO). Thus, there was a risk of losing a good amount of Condensate if proper measures were not taken.
This study focuses on the strategy to target these Condensate banks being accumulated at different locations of the Field, which has given an increment of around 30% already in the condensate production rates. Since the reservoir pressure has already dropped considerably below the dew point pressures - conventional CO2 or Lean gas injections cannot be utilized as they require significant re-pressurization which is technically and economically impossible at this stage of field's life. In this study, an alternative approach taken, is presented which increases the overall condensate recovery by almost 90%. This includes drilling smartly placed production wells (at locations which were not very attractive in the start of field development) and the overall impact of placing the injectors for Selective Water Flood using comprehensive reservoir simulation and water flood algorithms.
This paper illustrates the approach that can be utilized in a mature gas condensate field where no pressure maintenance has been performed since the start - to improve the overall condensate recovery. This paper presents a clinical analysis of targeting the Condensate banks and possible usage of selective water flood strategy to sweep these banks along with the optimum placement of wells and injectors. This offers an innovative approach towards such gas condensate fields which are facing the problems of condensate drop out and re-pressurizing the field to a higher Reservoir pressures, at current stage, is next to impossible.