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
Soroush, H. (PETROLERN LLC) | Ginty, W. (PETROLERN LLC) | Pan, C. (PETROLERN LLC) | Ferguson, W. (Rockfield) | Bere, A. (Rockfield) | Farid, S. M. U. (Pakistan Petroleum Limited) | Ahmed, H. (Pakistan Petroleum Limited) | Asghar, A. (Pakistan Petroleum Limited) | Hussain, Z. (Pakistan Petroleum Limited)
ABSTRACT: Attempts to stimulate a partially fractured tight carbonate reservoir in the Naushahro Feroz field in Pakistan indicated that fracturing without sufficient understanding of the in-situ stresses and rock mechanical properties is a huge risk. These initial attempts included a matrix acidizing job followed by a pulsated proppant fracturing job and eventually an acid-fracturing job. Despite this, the resulting production rates were not sustainable.
A geomechanical study was then carried out with the hope to improve the production from the tight reservoir. The study started with developing geomechanical models for the field, including both 1D and 3D models, using data from the vertical exploration well and its deviated side-track. The models were eventually updated using data acquired in the horizontal well drilled for stimulation. The geomechanical model, firstly helped to design and successfully drill the 1,300 m horizontal sidetrack; and secondly helped optimizing the zones selection and packer placement (10 zones) in addition to determining the maximum allowable drawdown to prevent wellbore failure during well testing. It also showed that the overlaying shale has potential to act as a weak containment.
Both proppant and acid fracturing jobs were modelled based on the geomechanical data and concluded that proppant fracturing was a better option for this specific reservoir considering the elevated temperature, high fracture closure pressure, and the orientation of natural fractures to the well trajectory. However, due to risk of proximity of formation water level to the toe zone, it was decided to perform Closed Fracture Acidizing (CFA) in the zones closer to the water spill point. While this stimulation technique limits the fractures height growth, it maintains conductivity and creates longer etched fracture length by maximizing differential acid etching through fingering as well as acid retardation.
Finally, based on the models, the optimum designs for each zone were proposed and the expected geometry (height, extension and orientation) were simulated using 3D geomechanical analysis.
The integrity of well construction plays an important role to recover the hydrocarbons from subsurface to surface safely and economically. The poor cement integrity behind the casing becomes the cause of gas migration and ultimate well abandonment. The lower Indus basin of Pakistan has the majority of gas producing wells and some of them are plugged due to poor cementing. This is caused by the substantial decrease in the performance of cement slurry with increase in temperature as a function of depth.
Therefore, it is essential to improve the API properties of cement slurry at high temperature for minimizing fluid loss and preventing the gas migration. For this purpose, different types of polymer have widely been used as the additives in cement slurry, but those polymers show thermal thinning behavior above 158 °F temperature. Polymers have also been modified by adding chemicals to improve their thermal stability range. However, the addition of chemicals affects the properties of other additives and increases the cost of cementing operation.
This paper presents the incorporation of Hydroxypropylmethylcellulose (HPMC) cellulose type polymer in cement slurry which acts as a thickener, film foamer and water retention agent. It is capable of increasing the viscosity at elevated temperature. The viscosity of HPMC solutions was determined experimentally at different temperatures ranging from 86 °F to 212 °F with respect to shear rates. The HPMC polymer showed remarkable rheological properties as a thermal thickener at 194 °F. HPMC solution was then combined with cement slurry to evaluate its API properties such as rheology, fluid loss, free water settling, thickening time and transition time at 194 °F. The experimental results showed that HPMC based cement slurries have significant rheology, minimal fluid loss, zero free water, extended thickening time. The transition time of slurries was less than 45 minutes which is considered as the excellent cement slurry for preventing gas migration as per API standards.
It is concluded that HPMC based cement slurries performed as the multifunctional additive, which successfully improved the properties of slurry and prevented the gas migration at high temperature. Hence, field application of HPMC polymer will be a prominent and a cost effective technique for the petroleum industry during cementing operation in the lower Indus basin, Pakistan.
Schedule Session Details Expand All Collapse All Filter By Date All Dates Sunday, November 12 Monday, November 13 Tuesday, November 14 Wednesday, November 15 Thursday, November 16 Filter By Session Type All Sessions Social and Networking Events Technical Sessions Panel, Plenary, and Special Sessions Training Course/Seminar Sunday, November 12 08:00 - 17:00 Production Optimisation System Instructor(s) Atef Abdelhady The basic objective of this course is to introduce the overview and concept of production optimisation, using nodal analysis as a tool in production optimisation and enhancement. Learn More 08:00 - 17:00 Practical Depth Conversion and Depth Imaging for the Interpreter Instructor(s) Pavel Vasilyev Depth conversion of time interpretations is a basic skill set for interpreters. There is no single methodology that is optimal for all cases. Depth imaging should be considered an integral component of interpretation. If the results derived from depth imaging are intended to mitigate risk, the interpreter must actively guide the process. Participants will gain an understanding of depth conversion methodologies and QCs for validity of methods used. Learn More 08:00 - 17:00 Marginal Field Development and Optimisations Instructor(s) Abdolrahim Ataei Green fields today mostly can be regarded as marginal fields and successfully developed. It covers the complete assessment of the oil and gas recovery potential from reservoir structure and formation evaluation, oil and gas reserve mapping, their uncertainties and risks management, feasible reservoir fluid depletion approaches, and to the construction of integrated production systems for cost effective development of the green fields. This session will show how chip technology has resulted in a miniaturised Electron Paramagnetic Resonance (EPR) spectrometer for online monitoring of asphaltenes (a chemical that clogs oil wells). The EPR sensor technology developed in the laboratory has been successfully deployed in major oil and gas fields across the world. This technology is used to monitor the concentration of asphaltenes in real-time and to minimise the use of environmentally hazardous chemical inhibitors in energy production. Employee suggestions for improvement cover a wide variety of topics such as economic efficiency, productivity, safety, operability, environmental friendliness, and to a greater or lesser extent, has led to efficient and improved operations.
Ahmed, Hassaan (Pakistan Petroleum Limited) | Ali, Syed Dost (Pakistan Petroleum Limited) | Ansari, Muhammad Mubashir Yousaf (Pakistan Petroleum Limited) | Farid, Syed Munib Ullah (Pakistan Petroleum Limited) | Khan, Muhammad Wahaj Uddin (Pakistan Petroleum Limited) | Shaukat, Athar (Pakistan Petroleum Limited) | Jamil, Aamir (Pakistan Petroleum Limited)
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 under-designed 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.
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.