Africa (Sub-Sahara) Bowleven has started drilling operations at the Moambe exploration well on the Bomono permit in Cameroon. Moambe is the second well in a two-well program, approximately 2 km east of the first well, Zingana. It targets a previously undrilled Paleocene Tertiary three-way dip fault block containing multiple sands and will be drilled to an estimated 1620 m in measured depth. Both wells will be logged. Bowleven is the operator and holds 100% interest. Asia Pacific Murphy Oil discovered gas at its Permai exploration well in deepwater Block H in the South China Sea offshore Malaysia.
Ashraf, Qasim (Weatherford International Ltd.) | Khalid, Ali (Weatherford International Ltd.) | Luqman, Khurram (Weatherford International Ltd.) | Hadj-Moussa, Ayoub (Weatherford International Ltd.) | Shafique, Muhammad Bilal (MOL Pakistan Oil & Gas Co. B.V.) | Abbas, Khurram (MOL Pakistan Oil & Gas Co. B.V.) | Tashfeen, Muhammad (MOL Pakistan Oil & Gas Co. B.V.) | Khan, Shahjahan (MOL Pakistan Oil & Gas Co. B.V.) | Jameel, Rizwan (MOL Pakistan Oil & Gas Co. B.V.)
The Northern Potwar Plateau of Pakistan is known for its severe geological features. Many wells have been drilled in the region, but geological correlations in neighboring fields have proven to be challenging. Excessive tectonic activity and faults have resulted in formation repetitions, abnormal in-situ stresses, and variable formation pore and fracture pressures.
One such field in the region is MDK field, where the operator was in the process of drilling a second well. Drilling of the 8 ½-in. hole section was in progress at 11,004 ft. (3,354 m) when the Bahadur Khel Salt formation was encountered. Upon drilling further into the formation, the operator encountered severe hole stability issues coupled with lost circulation. While in the salt formation, whenever circulation was stopped and annular pressure losses were eliminated, the drill string would become stuck. Upon resuming circulation, the pumping pressure would rise abruptly. The formation was highly stressed and was exhibiting a creeping behavior. Any reduction in the bottom hole pressure (BHP) would cause the formation to creep into the wellbore.
The operator spent a month attempting to drill through the highly stressed plastic salt formation, without success. The oil-based mud system was already weighted up to its maximum, and no other conventional means existed of controlling the creeping salt. The operating company had already spent ~USD 19 million dollars on the well, and was considering abandoning it after a nearby well in the same formation had been abandoned despite four unsuccessful sidetracks.
Maintaining a constant bottom hole pressure (CBHP) across the formation at all times was the only way to stabilize the salt formation and lost circulation treatment. Only managed pressure drilling (MPD) could achieve the application of CBHP. An MPD system would enable the operator to compensate for the lack of BHP by applying surface backpressure, thereby maintaining the target pressure across the formation at all times. With the help of the MPD system, the operator also sought to calculate the formation creep rate, so as to evaluate a time window for running in and out of the hole.
Besides drilling, the operator also intended to isolate the challenging section with a liner. With proper planning, the MPD system could help to achieve this objective.
A full MPD system was deployed to the wellsite and drilling resumed with a CBHP in dynamic and static periods. By CBHP MPD, the operator was able to tag bottom. Drilling and underreaming of the 8 ½-in. hole section resumed and continued until reaching the target depth of 14,745 ft. (4,494 m). After drilling, the 7-in. liner was set and cemented to the target depth using MPD.
Applying CBHP MPD enabled the operator to drill through 3,832 ft. (1,168 m) of the hole section and save the well from abandonment. This paper studies the design, execution, and lessons learned when applying MPD on the subject well.
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
By International Petroleum Technology Conference (IPTC) Monday, 25 March 0900-1600 hours Instructors: Olivier Dubrule and Lukas Mosser, Imperial College London Deep Learning (DL) is already bringing game-changing applications to the petroleum industry, and this is certainly the beginning of an enduring trend. Many petroleum engineers and geoscientists are interested to know more about DL but are not sure where to start. This one-day course aims to provide this introduction. The first half of the course presents the formalism of Logistic Regression, Neural Networks and Convolutional Neural Networks and some of their applications. Much of the standard terminology used in DL applications is also presented. In the afternoon, the online environment associated with DL is discussed, from Python libraries to software repositories, including useful websites and big datasets. The last part of the course is spent discussing the most promising subsurface applications of DL.
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.
Ashraf, Qasim (Weatherford International Ltd) | Khalid, Ali (Weatherford International Ltd) | Ali, Farhad (Weatherford International Ltd) | Luqman, Khurram (Weatherford International Ltd) | Mousa, Ayoub (Weatherford International Ltd) | Babar, Zaheer Uddin (Pakistan Petroleum Limited) | Hussam Uddin, Muhammad (Pakistan Petroleum Limited) | Ullah, Safi (Pakistan Petroleum Limited)
An operator has drilled more than 32 wells to date in Adhi field, a gas and condensate field in northern Pakistan. The majority of these wells produce from depleted sands and some also produce from limestone reservoirs. The wells range in depth between 8,366 and 11,483 ft (2,550 and 3,500 m).
The operator was in the process of drilling the 8 1/2-in. hole section with the least possible mud weight to minimize the overbalance across the lost-circulation-prone limestone formation. While drilling the section, an unexpected gas pocket was encountered and subsequently required an increase in mud weight. To further add to already challenging drilling conditions, a fault was expected in the middle of the section. This fault was expected to produce total losses. The resulting loss of hydrostatic head would have caused a troublesome well-control scenario.
The above conditions led to an inherently tight drilling window. The operator thus made precise management of wellbore pressures a prime objective. However in conventional drilling, relying on the mud weight and pumping rate for accurate management of wellbore pressures proves highly inefficient, if not impossible.
A managed pressure drilling (MPD) and underbalanced drilling (UBD) hybridized system was devised to enable drilling the 8 1/2-in. hole section. An MPD system that applies constant bottom hole pressure would enable drilling the section with the least possible mud weight and as close as possible to the pore pressure line. In the event that heavy to total losses were encountered because of the predicted fault, the system could be switched over to UBD flow drilling. By switching over to UBD, the equivalent circulating density (ECD) would be reduced further and allow the well to flow while drilling and mitigating losses.
An MPD and UBD system was also expected to offer numerous benefits in drilling, including reduced chances of differential sticking, reduced formation damage, increased rate of penetration and bit life, less washouts in the drillstring and pumps, reduced nonproductive time, and enhanced abilities to execute well control with the pipe in motion without fear of getting stuck.
The MPD and UBD hybrid system was deployed to the location. The operator was able to drill the 8 1/2- in. section to the target depth. The operator commenced drilling with an MPD system but, as expected, heavy losses were encountered. Drilling then proceeded with UB flow drilling until reaching target depth. The hybrid system enabled the operator to achieve target depth, eliminate an entire casing string, and substantially reduce NPT. This paper discusses the planning, design, and execution of the MPD and UBD hybrid system.
The Retrograde Gas-condensate systems have always been found unique both in their flow behavior and their ultimate recovery. This is mainly because of the process of condensation that takes place around the wellbore creating a region of condensate drop out resulting in flow impedance. In addition to it, the dependency of relative permeabilities on positive and negative velocities due to coupling and inertia respectively, further complicates the flow performance. These factors, thus, make an optimum production from these systems a very challenging and difficult task. Therefore, the main aim of this paper is to present a systematic approach towards the recovery optimization of such a low permeable gas condensate reservoir in Pakistan.
There are different production enhancement techniques that are applied to retrograde systems, among which Hydraulic Fracturing (HF) is a very common exercise. This Fracturing, however, also needs the optimization of geometry (i.e. width and length) and flow (i.e. rate) parameters to make it of high value. But, in some instances, despite of the enhanced flow behavior by HF, considerable amount of valuable gas and liquid might still be lost. Therefore, the recovery can be further optimized through techniques such as Water Flood (to increase the pressure back above the dew point), Miscible Gas or CO2 flooding etc.
This study first illustrates the impact of coupling and inertia on hydraulically fractured wells, using 3D reservoir simulation on real time data. A one well sector model is initially developed after validating the history match of the whole field model. Afterwards, the data from the Hydraulic Fracturing jobs, is incorporated to evaluate the positive and negative effects of the gas velocity, along with the recommendations on frac-geometry optimization for such gas condensate reservoirs.
The paper then illustrates the application of different Enhanced Oil Recovery methods on the whole field, using detailed compositional simulation, keeping in view the limitations of hydraulic fracture - as it may not be the answer to optimized recovery. Eventually, a comprehensive strategy has been presented, summarizing all the factors having maximum influence on the ultimate recovery and illustrate the operational and economic aspects of such technologies, to increase the overall gas and condensate production from the field.
Adhi gas-condensate field is located near Islamabad, Pakistan. Pakistan Petroleum Limited started fluid processing and recovery of Liquefied Petroleum Gas and Condensate around in 1990. The liquid stream was processed with no solids deposition in the past. Recently, the liquid processing circuit of the plant has experienced an increasing amount of black solid deposition, which is trapped into the liquid filters located in the plant.
To identify the root causes of the problem of these solids depositional systematic approach was applied including taking various solid, liquid and gas samples from the plant inlet and various locations inside the processing plant and analyzing them for diagnostics.
Based on the outcome of the root-cause analysis, a chemical mitigation strategy has been developed, tested and implemented, resulting in significant reduction in problems related with solid depositions in processing plant.
Adhi gas condensate field is located near Islamabad, Pakistan. The fluid in Adhi is processed in two liquefied Petroleum Gas (LPG)/Natural Gas Liquid (NGL) plants (plants I and II) and Oil Stabilization Facility (OSF). The condensate was processed without solid deposition in these plants from 1990 to 2007.
The black solid deposits started to accumulate on the process equipment and plants' filters (Figure-1)leading to a high filter change frequency and consequent production loss.
Due to the continuous increase of the severity of the problem, a full Flow Assurance (FA) review of the field was carried out in order to mitigate the solid precipitation and problem of its depositions in plant. The first phase of the FA review was to conduct a Root Cause Analysis (RCA) where the main causes were identified including fluid compositional changes, temperature and pressure changes across the system, and incompatibility of mixing well streams with different compositions were identified to be the main causes for the asphaltenes dropout.
The RCA was based on the historical plant production data, fluid sampling, analysis results and asphaltene thermodynamic modeling.
The outcomes were:
This article details the methodology followed in solving the solid deposition problem at Adhi.