Africa (Sub-Sahara) Algeria awarded four of 31 oil and gas field blocks on offer to foreign consortiums in its first auction since 2011. Shell and Repsol won permits for the Boughezoul area in the north of the country, while Shell and Statoil won permits for the Timissit area in the east. A consortium of Enel and Dragon Oil was awarded permits for both the Tinrhert and the Msari Akabli areas. Circle Oil's CGD-12 well, located onshore Morocco in the Sebou permit, encountered natural gas at different levels within the Guebbas and Hoot sands. Wireline logging analysis confirmed a net 9.7 m of pay. The first test, over the Intra Hoot sands, flowed gas at a sustained rate of 2.21 MMscf/D through an 18/64‑in. The primary target, the Main Hoot sands, flowed at a sustained rate of 4.62 MMscf/D through a 24/64-in.
Arisandy, Mellinda (PETRONAS Carigali Indonesia Operations) | Mazied, Miftah (PETRONAS Carigali Indonesia Operations) | Putra, Bayu P (PETRONAS Carigali Indonesia Operations) | Yogapurana, Erik (PETRONAS Carigali Indonesia Operations) | B Mohd Idris, Jamin Jamil (PETRONAS Carigali Indonesia Operations) | Darmawan, Hendra I. (PETRONAS Carigali Kuala Lumpur)
This paper describes geochemistry analysis, hydrocarbon charge and entrapment model for prolific "MA" Block in the West Natuna Basin. Even though the area is currently at a mature exploration stage, the behaviour of hydrocarbon distribution in the area is still poorly understood and the link between discovered hydrocarbon and possible kitchens is still unknown. This study is an attempt to understand hydrocarbon expulsion, charging and entrapment in "MA" Block to de-risk further exploration efforts.
Several localized inverted half-grabens were identified through seismic interpretation. Nearby wells were then selected in evaluating source rock quality and maturity. In order to determine hydrocarbon expulsion model, 1D-3D burial history and thermal maturity models were constructed using integration of source rock and fluids geochemistry, temperature, seismic, and well data. Hydrocarbon charge and entrapment models were then simulated using 3D basin modeling software and calibrated with existing proven accumulation to produce a risked understanding of hydrocarbon distribution in the study area.
This study suggests that the most possible source rocks are the Late Eocene and Oligocene shales of Lama Formation and Lower Gabus Formations. Both source rocks are indicated by type I & type III kerogen. Lama source rock was confined in the initial grabens and post mature in deep paleo-grabens. This study confirmed that charging is derived from four (4) kitchen areas: Anoa, Gajah, Kakap, and Kambing grabens. The oil samples from "MA" Block indicated lacustrine facies. Rock geochemistry analysis portrayed oil-prone and gas-prone source rock.
In general, hydrocarbon was migrated from the southeastern area (Kambing graben) and southwestern area (Gajah graben). Hydrocarbon was later on accumulated in the nearest structural entrapments (anticlines). In the deep grabens (Kakap and Kambing), the hydrocarbon expulsion was starting as early as 37 Ma and 31 Ma, respectively, while in shallow graben (Anoa) the expulsion was starting at 29 Ma. The earliest structural trap commenced at 21 Ma, aligned with the initial compressional regime that was affecting the West Natuna Basin. Notable accumulative erosion in Miocene was nearly 1000 m at inverted structures, by which partly removed regional seal and reduced reservoir effectiveness. Significant yet-to-find hydrocarbon is predicted to be concentrated in the Anoa, Kakap, and Northeast Kambing area.
Is Surfactant Environmentally Safe for Offshore Use and Discharge? The current presentation date and time shown is a TENTATIVE schedule. The final/confirm presentation schedule will be notified/available in February 2019. Designing Cement Jobs for Success - Get It Right the First Time! Connected Reservoir Regions Map Created From Time-Lapse Pressure Data Shows Similarity to Other Reservoir Quality Maps in a Heterogeneous Carbonate Reservoir. X. Du, Y. Jin, X. Wu, U. of Houston; Y. Liu, X. Wu, O. Awan, J. Roth, K.C. See, N. Tognini, Shell Intl.
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.
Tham, Su Li (PETRONAS Carigali Sdn. Bhd.) | Ariffin, Mohd Hafizi (PETRONAS Carigali Sdn. Bhd.) | Johing, Fedawin (PETRONAS Carigali Sdn. Bhd.) | M Khalil, Muhammad Idraki (PETRONAS Carigali Sdn. Bhd.) | Dolah, Khairul Arifin (PETRONAS Carigali Sdn. Bhd.) | Yusop, Zainuddin (PETRONAS Carigali Sdn. Bhd.)
Water injection was implemented in a 30-year old brownfield offshore Sarawak, Malaysia in August 2016. Seawater is processed at a Water Injection Facility (WIF) and sent to four injectors, each injecting commingled into two or three different reservoirs. This paper discusses on challenges faced in initial start-up of water injection in a brownfield including the inability to meet target injection rate, frequent WIF trips and off-spec injection water, metering issues, as well as mitigation measures and lessons learned.
Initially, the injectors were able to take in only 33% of target injection volume as per the FDP plan. To remedy this, a ramp-up injection procedure was introduced to allow the injectors to gradually take in more water until the target injection rate could be achieved. A leaner and practical water quality SOP was devised to reduce injector downtime, particularly for satellite platforms, while ensuring water quality is not compromised. Injection fall-off testing was performed on the injectors to investigate the root cause of the injectivity issue through manipulation of downhole ICV. Through this exercise, it was discovered that the injection meters were not properly calibrated.
A combination of these methods proved successful in improving injection rate of the water injectors. Initial SOP developed for the injection water quality required testing of water quality at each sampling point including at unmanned satellite platforms, prior to recommencement of water injection post WIF shutdown. This is despite the duration of shutdown being shorter than the frequency of required sampling, which led to prolonged injection downtime. The requirement for water sampling for satellite platforms were modified to be less stringent while still maintaining good water quality. As a result, there was an improvement in WIF uptime from 92% in second month of injection to 99% in the fifth month.
The fall-off testing provided valuable information in terms of well and reservoir data. Careful and specific operational steps were required to adjust the downhole ICVs during fall-off testing, as opposed to hard shut-in of the water injectors which would cause backpressure and tripping of the WIF. Adjustment of the surface-controlled ICVs allowed sequential testing of different zones, which successfully shortened the total testing duration by 25%. The fall-off test also revealed that an injector was injecting into a reservoir which did not benefit any producers, and that the flowmeters for certain injectors were not calibrated properly.
Through these efforts, injection rates were successfully increased by 25 kbwpd, from 35% to 75% of the total injection target, within six months of its implementation. Water injection start-up challenges and mitigation methods are not often discussed in literature, such as adjustments needed to achieve target injection rate, operational steps in well testing for commingled injectors, and finding the optimum balance between quality and practicality of injected water testing. It is hoped that the issues and strategy in this field will serve as lessons learnt for upcoming water injection projects in this and nearby fields.
Praditya, Yusuf Alfyan (Premier Oil Indonesia) | Satiawarman, Anugerah (Premier Oil Indonesia) | Nurrahman, Fahmi (Premier Oil Indonesia) | Medianestrian, Medianestrian (Premier Oil Indonesia) | Rochaendy, Risnawan (Premier Oil Indonesia)
Wells which produce dry gas reservoirs usually have low bottomhole pressure. But in many instance liquid is associated with the produced gas, it can come from the liquid in reservoir or condensed production liquid. When more liquid is introduced into the wellbore, the pressure gradient along the wellbore is higher. The increased liquid fraction creates higher backpressure on the reservoir delivering gas. In high pressure gas reservoir the presence of liquid can occur in several degree of bubble and slug flow; in depleted gas reservoir the liquid can kill the well as the gas does not have enough transport energy to lift the liquid. At the point when the gas velocity is insufficient to carry out liquid, liquid will start to drop and accumulate in the bottomhole creating a restriction on the gas flow path, the phenomena is called liquid loading.
This paper presents success case studies from Premier Oil Indonesia in handling and reactivating four liquid loaded gas wells in Natuna Sea offshore operation. Wellbore configuration and facility limitations in offshore operation (e.g. maximum deck load capacity, water handling capacity and crane capacity) create more complexity of the method selection in comparison to onshore operation. There are many gas well deliquification methods available in the industry, but not in instance that each method is appropriate for all conditions. The case studies presented in this paper provide description of how Premier Oil Indonesia screened several available gas well deliquification methods in the industry and came up with the water shut off proposal as the best and most proper method for its wells. The understanding of liquid loading indication, liquid source identification and operational details of gas well deliquification methods are the most important factors to determine the most effective and cost efficient method to handle liquid loaded wells. This paper also presents a general guideline in selecting the best gas well deliquification method for some specific cases under several operational conditions for onshore and offshore operations.
Liu, Teng (China National Offshore Oil Corporation (CNOOC) Ltd., Tianjin Branch, Tianjin, P. R. China) | Wang, Jun (China National Offshore Oil Corporation (CNOOC) Ltd., Tianjin Branch, Tianjin, P. R. China) | Zhang, Jingsi (China National Offshore Oil Corporation (CNOOC) Ltd., Tianjin Branch, Tianjin, P. R. China) | Zhang, Li (China National Offshore Oil Corporation (CNOOC) Ltd., Tianjin Branch, Tianjin, P. R. China) | Sun, Xijia (China National Offshore Oil Corporation (CNOOC) Ltd., Tianjin Branch, Tianjin, P. R. China) | Bian, Li’en (China National Offshore Oil Corporation (CNOOC) Ltd., Tianjin Branch, Tianjin, P. R. China)
In order to study the reservoir forming mode of lithologic reservoirs in Block A of Shijiutuo Uplift gentle slope belt in Bohai Oilfield, and to predict favorable zones for exploration, it is necessary to characterize the distribution form of sedimentary system under sequence framework, analyze the oil and gas preservation conditions of reservoir roof and floor and uphill plugging conditions. First, the time-frequency analysis technique is used to divide the 2D system domain of the well finely, and then the Wheeler domain transformation technique based on the seismic data is used to generalize the result of the division of the well to the 3D space, to establish the fine system domain framework rapidly, and to carry out reservoir prediction and analysis of preservation conditions.The results show that: 1) shijiutuo Uplift gentle slope belt is close to the main sag of the Qinnan hydrocarbon-rich sag, and the hydrocarbon accumulation condition is superior. 2) The long term active faults and delta sand bodies in the area are combined to form a multiplex transport network, which is beneficial to the formation of lithologic oil and gas reservoirs. 3) The nose-like structure of the gentle slope zone is an important direction and track of oil and gas migration. Once the upslope direction has plugging condition, the oil and gas reservoir can be formed. On the whole, the preservation and plugging conditions of Block A of Shijiutuo Uplift gentle slope belt in Bohai Oilfield are favorable for the exploration of lithologic reservoirs.
Presentation Date: Monday, October 15, 2018
Start Time: 1:50:00 PM
Location: 210A (Anaheim Convention Center)
Presentation Type: Oral
In an effort to reduce project construction and start-up costs, novel and alternative well construction models have been developed and adopted globally. One such approach is to adopt a segregated drilling campaign, the well construction and completions operations can be segregated into two distinct phases. A drilling and casing phase leaving a cased well in a Temporary Abandonment (TA) status, followed by a phase consisting of WBC (wellbore clean-up), completion and stimulation operations resulting in the handover of the well to production to bring hydrocarbon production online. As such this provides an opportunity to reduce surface equipment specification and costs, in comparison to that which is required for drilling activities. A potential solution exists by utilising alternative technology with the capability to perform perforation, multi-zone completion installation, stimulation, WBC operations and well testing, at comparatively lower cost than conventional drilling technology. This paper describes the collaborative development of such technology, and focuses on the definition of the surface equipment requirements and specification phase, pertaining to the typical downhole operations required to be executed during the multi-zone completion installation, stimulation, WBC operations and well testing. Each operation is assessed to give a base required capability, with further operations that are deemed to have a critical effect on the efficiency and duration, identified. A typical anticipated operations program is presented and the study focuses on the first principle requirements of each of the steps. Further operation considerations are presented and discussed for each operational step, forming the basis of discreet specifications per step. Further, the identification of operations not on the critical path that can be performed simultaneously or as an offline activity, have the potential to make high cost impacts. Collaboration between the Yangon based operator and service provider drives a design which provides a technically pragmatic and capable ICU (Intervention and Completion Unit) and as such attracting project cost savings allied to lower support equipment costs. Further, the deployment flexibility of the ICU allows it to perform operations ranging from well construction activities such as well slot preparation, completions and intervention, to well deconstruction activities such as heavy workover, Permanent Abandonment (PA) phases and slot recovery. The ability to perform multi-phase operations whilst mobilized to a platform brings further cost benefits and operational flexibility.
This paper documents the findings based on interpretation of the geochemical composition of oils from the Bualuang Field located in the western Gulf of Thailand, and how these oils compare with other oils and potential source rocks in the region. The Bualuang Field is located in Block B8/38, on the eastern flank of one of a series of north-south trending, Tertiary half-grabens which are part of the greater Western Basin.
Eight oil samples from five wells on the Bualuang Field were analysed using gas chromatography (GC), gas chromatography-mass spectroscopy (GC-MS) and carbon isotopic techniques. Selected samples were further analysed by GC-MS-MS. This paper provides a review of these analyses, presenting key geochemical evidence for the likely age and facies of the source of this oil. A comparison is then made between the Bualuang Field oils and other oils from the immediate surrounding area as well as more regionally. In addition, the oils are considered against potential Mesozoic source rocks observed in peninsular Thailand.
The molecular and isotopic analysis of the Bualuang oils show strong similarity, and origin from a carbonate facies (probably marly) as indicated by dominance of C29 hopane over C30 hopane, presence of significant C30 30-norhopane, abundance of C24 tetracyclic terpane and low amounts of diasteranes. Furthermore, the oils are believed to have a marine origin due to the presence of C30 steranes (confirmed by GC-MS-MS), a C26/C25 tricyclic terpane ratio in excess of 1, and the stable carbon isotopic composition. The source of the Bualuang oil is considered older than Tertiary because of the absence of oleanane (typically significant in Tertiary oils), the dominance of 27-norcholestanes (24-norcholestane ratio
Importantly this paper provides strong, albeit indirect, geochemical evidence for an additional oil-prone source to consider within the western Gulf of Thailand, which is believed to be Mesozoic in age. One of the key exploration challenges is related to identifying the presence and extent of such a Pre-Tertiary source on seismic data.