Africa (Sub-Sahara) Bowleven's Moambe exploration well on the Bomono Permit onshore Cameroon has encountered hydrocarbons. The well was drilled to a planned total depth of 5,803 ft and made its discovery in Paleocene-aged (Tertiary) target reservoir intervals. Moambe is the second in a two-well exploration program on the permit. The first well, Zingana, also discovered hydrocarbons. The Moambe well will be tested before further testing takes place at Zingana. Bowleven holds 100% interest in the permit. Shell Nigeria Exploration and Production has begun production at the Bonga Phase 3 project, an expansion of the deepwater Bonga project in Nigeria. Peak production from the expansion is expected to be 50,000 BOEPD, which will be shipped by pipelines to the Bonga floating production, storage, and offloading facility.
Africa (Sub-Sahara) Eni started production from the West Hub development project's Mpungi field in Block 15/06 offshore Angola. The startup follows the project's first oil from the Sangos field in November 2014 and the Cinguvu field last April. Mpungi will ramp up West Hub oil production to 100,000 B/D in the first quarter from a previous level of 60,000 B/D. The project also includes the future development of the Mpungi North, Ochigufu, and Vandumbu fields. Eni is the block operator with a 36.84% stake. Sonangol (36.84%) and SSI Fifteen (26.32%) hold the other stakes.
Africa (Sub-Sahara) Marathon Oil has produced first gas from its Alba B3 compression platform offshore Equatorial Guinea. The startup enables the company to convert approximately 130 million BOE of proved undeveloped reserves, which more than doubles its remaining proved developed reserve base in the country. Marathon holds an operating interest of about 65% in the field, with Noble Energy holding the remaining stake. Aminex said that gas production from the Kiliwani North-1 well in Tanzania has reached 30 MMcf/D (about 5,000 BOE/D). The project's commissioning process is expected to conclude with a well test to determine the optimal production rate, which previous test data suggest will be approximately 30 MMcf/D, the company said. The operator of the Kiliwani North Development License, Aminex holds a 54.575% interest in the well.
Africa (Sub-Sahara) Shell has initiated a two-well drilling program in blocks 1 and 4 of the Mafia Deep basin offshore Tanzania. Drilling is taking place in water depths of up to 7,545 ft, with the company and its joint-venture partners Pavilion Energy and Ophir Energy investing almost USD 80 million in the program. The two wells will meet the remaining requirements in the exploration licenses issued by the Tanzanian Ministry of Energy and Minerals. Asia Pacific Petronas has begun gas production from the world's first floating liquefied natural gas (FLNG) facility, the PFLNG SATU, at the Kanowit field offshore Malaysia's Sarawak state. The first-gas milestone marked the onset of commissioning and startup for the FLNG facility, preceding commercial production and initial cargo shipment. The facility is fitted with an external turret for operating in water depths of 229 ft to 656 ft. It will extract gas through a flexible subsea pipeline for the liquefaction, production, storage, and offloading of LNG at the field.
Du, Qizhen (School of Geosciences, China University of Petroleum-East China) | Yasin, Qamar (School of Geosciences, China University of Petroleum-East China) | Ismail, Atif (Department of Geological Engineering, University of Engineering and Technology Lahore, Pakistan)
Verifiable and accurate estimation of shear wave velocity (VS) in a well with no previous exposure of velocity profile is the bottom line for any technique to declare the VS estimation capabilities. So far all the available models and techniques for VS estimation have been attempted on well logs and laboratory based core measurements. This study aims to compare the role of virtual measurement using Artificial Neural Network (ANN) and rock physics analysis using Gassmann equation for the estimation of VS in a highly heterogeneous reservoir. The techniques were applied initially to the well containing specialized logging and laboratory analysis data and prediction of VS models were developed. The developed model was then applied to the offset well whose data was not included in the model development and the results were compared with measured VS data. The results show that although rock physics model provides acceptable results that show consistency in following the actual trend in shear and compressional wave velocities estimation it lacks a consistent generalization power, meaning that it does not work as well with the data of unstable zones. On the other hand, ANN provides more realistic results because of its discriminatory power and observe the actual trend in VS estimation even at unstable zones.
Presentation Date: Wednesday, October 17, 2018
Start Time: 9:20:00 AM
Location: Poster Station 1
Presentation Type: Poster
This paper presents the modern and fit for purpose methodologies, challenges with mitigation, special consideration from geological, drilling and completions to successfully deliver first deep horizontal well with lateral length of ~1300 m and open hole multistage fracking in tight carbonate reservoir in Lower Indus Basin of Pakistan. The paper also discusses economic feasibility of making re-entries into suspended vertical wells in generally high cost services infrastructure in Pakistan. The methodologies include special deliberations on; scenario based Geomechanics Modelling, Wellbore Placement Optimization along with economic analysis by using Re-Entry versus New Well, Formation Behaviors, Drill String Design, Drill Bits Design, Hydraulics and Torque and Drag (T&D) modelling with friction factor calibration, Drilling Fluid and Strategies, Downhole Problems & Mitigations, Wellbore Quality for Open hole Multistage Fracking – All challenges, associated risks are discussed and mitigated in detail.
There were two main challenges in the wellbore placement; first is the requirement of wellbore to intersect maximum critically stressed fractures that required a new wellbore to drill and intersect but the economics of new wellbore was not feasible. Drilling team optimized the placement of the well and utilized an existing suspended wellbore to align well trajectory without compromising multistage fracking requirements. This had significantly reduced well cost and enabled the operator to proceed further. The second challenge was the wellbore failure that might have compromised hole quality and multistage open hole fracking on which the project economics based heavily. Two different fault regimes were present around the well that made the placement of wellbore more challenging. Wellbore trajectory was refined with multiple sensitivities of Geomechanics to fit the safe mud weight window. The LWD suits were run to enable the Geosteering in to sweet fractured zones. T&D model was developed and calibrated at real-time to take decisions. The drilling fluid was designed with special additives to encompass high temperature and stress caging of formation to prevent wellbore failure as well as to reduce Torque and Drag. Bit designs are also revamped that successfully drilled high UCS formations with minimal thermal cracking & favoring the RSS system to achieve landing the full lateral within top 30 m of formation. All aspects were thoroughly addressed and mitigated successfully resulting in to successful deliverables of the well project within the stipulated time and cost.
The holistic approach presented in this paper had addressed special considerations to be given to successfully deliver horizontal wells with multifracking in tight gas reservoirs in Pakistan by rerunning economic sensitivities of already suspended wells in premature tight gas fields that restrained operators to further work on development due to failure of earlier similar projects and negative economics.
Dumpflooding technique is defined as intentional cross-flow of water from a high pressure layer into depleting oil producing zone for the purpose of pressure maintenance. It is a highly economical method to improve oil recoveries as it requires no capital and operational expenses. After implementation, however, it is challenging to maintain optimal injectivity in dumpflooded potential oil zone given the nature of its subsurface process without direct measurements and monitoring.
This paper describes a case study of oil field discovered in 1993 by drilling of N-1 well which successfully penetrated two Sandstone reservoirs (B & C Sands). Open-hole logging and formation testing confirmed presence of oil in both Sands. Pressure production history of N-1 and subsequently drilled three developments wells determined C Sand to be moderate-to-strong water drive reservoir, whereas, B Sand witnessed poor pressure support with faster decline in oil production. Due to remote nature of this field, a full-fledge water injection project did not attract economics. In order to improve recovery of B Sand, it was evaluated to initiate dumpflood at the third development well, N-4, where C Sand was watered out. Geological analysis of the logs/core data suggests B Sand to be a laterally extensive Sand body, supporting the use of the dumpflooding technique in the given area. Engineering analysis was carried out using nodal analysis and tank models to estimate injection rates and additional recovery. After evaluating technical feasibility, dumpflooding was recommended and implemented at N-6, most downdip well located at Northern structure. The impact of dumpflood was realized on liquid withdrawals as well as pressures of B Sand. The injection performance of N-4 was routinely monitored and maintained through remedial measures. This way, the successfully implemented and well managed dumpflood process achieved significant increase in oil recoveries of the field.
The dumpflood technique is injection of water into target zone for pressure maintenance by allowing water to flow naturally from a reservoir at higher pressure. This technique was successfully implemented and maintained in a field discovered in Badin district of Sindh, Pakistan. Exploratory well N-1 was drilled to the depth of around 7,000 ft and found hydrocarbon pay in B & C Sands which were later confirmed to be oil bearing based on formation testing results. N-1 was commissioned in April 1993 and produced at initial rates of 2.5 Mbopd without any water production. Over the period of around 5 years, N-1 exhibited weak pressure support in B Sand - declining liquid withdrawals with depleting reservoir pressure determined through pressure surveys. This decline became steeper when withdrawals were increased by putting N-1 on Jet Pump lift. N-4, a subsequent development well, was commissioned from B Sand in year 2000 and witnessed similar B Sand behavior.
Pressure maintenance scheme was evaluated to enhance B Sand recoveries, however, a full-fledge water injection plan showed marginal economics against significant capital required for a remote field. Meanwhile, sufficient C Sand pressure and production history (Fig-7) became available from first development well N-2, this history showed C Sand to have a strong pressure support as it depleted by less than 100 psi after producing around 4 MMbbls liquid. In year 2001, another N-6 was drilled in the northert part of the structure but found both B & C Sands wet.
Dumpflood water injection plan was recommended from N-4 due to its structural position and B Sand lateral continuity (Fig-2). The response of dumpflood was quickly realized at both of then B Sand producers – N-1 and N3. As a result, application of successful dumpflood scheme additional oil recovery of around 20% in B Sand.
Noman, Muhammad (United Energy Pakistan Limited) | Khan, Muhammad Nisar (United Energy Pakistan Limited) | Amjad, Bilal (United Energy Pakistan Limited) | Afsar, Javaid (United Energy Pakistan Limited)
Analyses of dynamic data that include pressure and production history have long been recognized as a tool to evaluate the underground reservoir size, fluid volumes and future performance. This study encompasses a similar case utilizing analytical and numerical methods to interpret the dynamic data. As a result several geological features were confirmed and a few sub-seismic features were identified.
The field under discussion is located in Lower Indus Basin of Pakistan and characterized by hydrocarbon accumulations in Lower-Goru Upper-Sand reservoirs. Exploratory well A-1 discovered the field by finding gas bearing Sandstone reservoir established based on formation evaluation and open-hole log profile. The structure was bounded by two major intersecting faults and one splay fault, all juxtaposed against shale barriers. Due to these structural features A-Sand was expected to exhibit depletion drive mechanism. When A-1 was put on production, it performed as a dry gas producer for brief period of time then its gas rates started declining with increasing CGR. Routine surveillance recorded depletion in reservoir pressure and the well loaded up after a year. After reviving on Gas Lift and A-1 became essentially an oil producer with a GOR of 2000 scf/stb. BHP surveys showed no further depletion than 400 psia. These facts hinted at pressure support to A Sand reservoir as opposed to originally assumed closed structure. To enhance oil production hydraulic jet pump was installed and achieved apex oil rates from the well, interestingly, without commensurate increase in water production. On Jet Pump also, well exhibited fairly constant liquid withdrawals strengthened idea of pressure recharging. To identify source of A-Sand recharging, it was decided to (1) analyse pressure-production history (2) Closely analyse interpreted analytical model built on pressure data (3) Perform numerical PTA by integrating G&G data, and (4) develop Allen diagrams to see possible juxtaposition with downthrown blocks.The study concluded that Splay fault on reservoir structure may not be completely sealing since both Analytical and Numerical Model transient models strongly suggested slightly different position of splay fault on the west of the well. Allen Diagram further showed decreasing throw of the same fault intimating possibility of juxtaposition. Hence, it was concluded that the oil source and pressure support most probably lies beyond the western fault and could be confirmed by refining subsurface structure through re-interpretation of seismic data.This way, the work emphasized the role of dynamic data in adding value to a company’s knowledge of subsurface elements and hence widen the scope of field development strategy.
Widening supply and demand gap in natural gas industry, the advent of tight gas policy and increasing interest of operators in tight gas sands and shale has opened new venues for development of unconventional plays in Pakistan.
Middle Indus Basin hosts important gas fields of Pakistan. Most of the wells in this basin are completed in conventional lower Goru Sands. Lower Goru formation consists of inter-bedded sequences of sands and shale. Its unconventional sand and shale plays hold immense potential which has not yet been exploited due to lack of technology and promising economics. Moreover, Sembar shale is the well known source rock in this basin holding large shale gas potential. GIIP estimates for Lower Goru tight sands excluding the shale prospects are 8.4 TCF which are considered pessimistic due to lack of data in many fields.
From the currently suspended or abandoned wellbores of the Middle Indus Basin, a pilot project needs to be defined in each of the fields, to prove the technical and economical feasibility of tight Gas Potential of the Basin. Commencement of production from unconventional sands will enhance the production in a cost effective manner due to availability of infrastructure and facilities.
This paper focuses on the utilization of existing wellbores as well as data set and highlighting additional data acquisition requirements coupled with completion and multi-stage fracturing techniques for designing a pilot project. Case study of a pilot project in one of the fields of this basin is discussed. It encompasses the basic workflow, candidate selection criterion, Geo-mechanics, sector modeling, hydraulic fracture design and risk evaluation coupled with its use in full field development projects.
Background and Introduction
Pakistan's last year 2010-2011 production was about 3.91bcf/d, while its demand was (4.2bcf/d) and supply gap was also started. Since then the production from the conventional fields has decreased, while demand has been increased due to infrastructure and human needs. This huge shortfall in the gas market cannot be fulfilled with existing number of completions/producers. The conventional reserves of the country were 56 TCF out of which the country has already produced 50% of its conventional reserves. The recoverable remaining reserves are 24-28TCF, but will be produced at much lower production rate and in much longer period of time. The country has an infrastructure of Gas Processing Facilities 5bcf/d.