Chen, Meiyi (College of Earth Science, Northeast Petroleum University) | Ji, Qingsheng (Exploration and Development Research Institute) | Chen, Shoutian (No.1 Geophysical Exploration Company of Daqing Drilling and Exploration Engineering Corporation) | Qin, Longpu (Exploration Department Daqing Oilfield Company Ltd) | Cong, Peihong (No.1 Geophysical Exploration Company of Daqing Drilling and Exploration Engineering Corporation)
Based on the seismic prediction difficulties of the tight sandstone reservoir in Fuyu formation in Zhaoyuan area, single-well sequence division and connecting-well sub-layer correlation are carried out according to logging and lithologic data, and short-cycle interface position is calibrated precisely after a mutual calibration of logging and seismic data. Horizon tracing in the whole area is also carried out to build highfrequency isochronous stratigraphic framework. On this basis, the log facies modes and the sedimentary facies of the short-cycles under a high-frequency isochronous stratigraphic framework are analyzed in the target area, sand-body geometric scale parameters and their relations and sand-body development degree are calculated out, and a sand-body geological model is also built out. According to the seismic data and layer-by-layer geological model of sand bodies, a spatial distribution probability model of facies-controlled sand bodies is built out, which is used to constrain the pre-stack seismic data in facies-controlled inversion calculation. Based on the results of facies-controlled inversion, the tight sandstone prediction is carried out. Finally, a method of isochronal facies-controlled pre-stack seismic inversion prediction of tight sandstone reservoir is formed and it realizes the effective prediction of superimposed sand bodies in target area. Compared with actual drilling results, the sandstone of more than 2m has clear depiction and the sandstone of between 1-2m also has response, which indicates that this method is feasible and practicable.
Yang, Ruoyu (Southwest Petroleum University) | Guo, Jianchun (Southwest Petroleum University) | Zhang, Tao (Southwest Petroleum University) | Zhang, Xudong (Southwest Petroleum University) | Ma, Jian (Sinopec) | Li, Yang (Southwest Petroleum University)
Slick-water fracturing treatment is one of the most effective method to develop shale reservoir, which creates complex fracture system by connecting the pre-existing natural fractures. However, the proppant transport and placement behavior is quite different from that in conventional bi-wing fractures due to the low viscosity fluid system and intersections between fractures. The goal of this work is to simulate and understand the characteristic of proppant transport behavior in Complex Fractures network.
A Eulerian multiphase model is introduced to simulate the transport and settling behavior in the hydraulic fracture network, which takes turbulence effects and friction stress between the proppant particles into consideration and fully couple the fluid phase with particle phase. Simulation work was conducted to investigate the control mechanism and influencing factors for proppant transportation from main fracture into secondary and tertiary fractures.
The simulation results indicate that a small proppant dune quickly forms in the main fractures first, and almost no proppant enters the lower grade fracture until the proppant dune in the intersection reaches a specific height. With continuous injection of slurry fluid, majority of the proppant enters in the lower grade fracture which is controlled by gravity rolling from the dune in main fractures and fluid drag force, and the proppant settles quickly and gradually reach their own equilibrium height. Parametric study shows that smaller proppant density and particle size can also help proppant transport into secondary fractures and form a higher equilibrium height dune, resulting in larger effective propped area. Moreover, when the lower grade fracture is closer to the inlet entrance, the proppant is more likely to transport in, and the height of sand dunes formed in the fractures is higher.
The proppant transport process in complex fracture systems is simulated by Eulerian Multiphase Model in this paper. This study extends the understanding of the process and mechanism of proppant transport in complex fracture system and controlling factors, which helps optimize hydraulic fracturing design in shale formation.
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.
Si, Xueqiang (Petrochina Hangzhou Research Institute of Geology) | Xu, Yang (Petrochina Hangzhou Research Institute of Geology) | Wang, Xin (Petrochina Hangzhou Research Institute of Geology) | Guo, Huajun (Petrochina Hangzhou Research Institute of Geology) | Li, Yazhe (Petrochina Hangzhou Research Institute of Geology) | Shan, Xiang (Petrochina Hangzhou Research Institute of Geology)
Sandstone can be divided into many types with reference to permeability and porosity. Some scholars and researchers have established criteria to classify tight sandstone by using porosity and permeability. Sandstone with permeability less than 1mD and porosity less than 10% could be called tight sandstone. Exploration and development of tight sandstone gas has become a hot spot of oil and gas exploration (Dai J. et al., 2002) in China. Quite recently, tight sandstone gas reservoirs of different scales have been discovered in the middle-lower Jurassic of Taibei Sag in Turpan-Hami Basin. The purposes of this paperare to analyze the texture and composition of the middle-lower Jurassic tight sandstones, investigate diagenesis type and reveal the influence of diagenesis on reservoir quality.
The earlier a stuck pipe incident is predicted and mitigated, the higher the chance of success in freeing the pipe or avoiding severe sticking in the first place. Time is crucial in such cases as an improper reaction to a stuck pipe incident can easily make it worse. In this work, practical machine learning, classification models were developed using real-time drilling data to automatically detect stuck pipe incidents during drilling operations and communicate the observations and alerts, sufficiently ahead of time, to the rig crew for avoidance or remediation actions to be taken.
The models use machine learning algorithms that feed on identified key drilling parameters to detect stuck pipe anomalies. The parameters used in building the system were selected based on published literature and historical data and reports of stuck pipe incidents and were analyzed and ranked to identify the ones of key influence on the accuracy of stuck pipe detection via a nonlinear relationship. The model exceptionally uses the robustness of data-based analysis along with the physics-based analysis.
The model has shown effective detection of the signs observed by experts ahead of time and has helped with providing enhanced stuck pipe detection and risk assessment. Validating and testing the model on several cases showed promising results as anomalies on simple and complex parameters were detected before or near the actual time stuck pipe incidents were reported from the rig crew. This facilitated better understanding of the underlying physics principles and provided awareness of stuck pipe occurrence.
The model improved monitoring and interpreting the drilling data streams. Beside such pipe signs, the model helped with detecting signs of other impeding problems in the downhole conditions of the wellbore, the drilling equipment, and the sensors. The model is designed to be implemented in the real-time drilling data portal to provide an alarm system for all oil and gas rigs based on the observed abnormalities. The alarm is to be populated on the real-time environment and communicated to the rig crew in a timely manner to ensure optimal results, giving them sufficient time ahead to prevent or remediate a potential stuck pipe incident.
Radzuan, Nurul Asyikin M. (PETRONAS) | Salleh, Nurfarah Izwana (PETRONAS) | Chandrakant, Ashvin Avalani (PETRONAS) | Rusman, Liyana (PETRONAS) | Zamanuri, Kautsar (PETRONAS) | Bakar, Azfar Israa Abu (PETRONAS) | Yip, Pui Mun (PETRONAS) | Jamaluddin, M. Helmi (PETRONAS) | Ghonim, Elsayed Ouda (PETRONAS) | Nambiar, Vijay (Novomet) | Alexander, Euan (Artificial Lift Solutions)
Following the first pilot success of the truly rigless 3-1/2" tubing cable deployed ESP (TTESP-CD in offshore field of Sarawak Basin, PETRONAS has taken steps to further advance in the technology development and application through more replications within Sarawak and Malay Basin. PETRONAS had been looking into a strong business case for the TTESP-CD technology for a wider application throughout Malaysia region by looking at fields with strong/moderate water drive and low bubble point pressure besides having other limitations on the platform including the facilities reliability issues. TTESP-CD are to be applied widely in Malaysia with more flexibilities in design and improvement towards the subsurface equipment, installation equipment and procedures. With the challenges in the existing completion and production requirement for replications, based on the lesson learnt from the pilot implementation, multiple improvements to the system have been done including; 1) A High Rate Slim Pump with Flexible Application 2) Alignment Tool for Cable Hanger Orientation. With this in place, more opportunities identified for the candidate selection which improve the installation philosophy specifically in dual string applications and enhance the efficiency in installation procedures. Case studies of TTESP-CD replications in Malay & Sarawak Basin for Field T, Field B and Field P presenting the best case for TTESP-CD application with improvement to design, equipment and application. These will bring additional value to PETRONAS with estimated production gain of 1.5 KBD and up to 1.2 MMSTB reserves to be monetized with additional value saving of up to RM 6 Mill. Besides the subsurface challenges, aging offshore assets brings a lot of challenges, especially on the space availability, structural integrity, power availability and distribution, instrumentation and data transmission. This requires an integrated approach from multiple disciplines in delivering the studies as per required within the targeted timeframe.
Ding, Shuaiwei (National & Local Joint Engineering Research Center for Carbon Capture and Sequestration Technology, State Key Laboratory for Continental Dynamics, Northwest University) | Liu, Guangwei (CNOOC Research Institute) | Li, Peng (National Engineering Laboratory for Exploration and Development of Low-Permeability Oil & Gas Fields) | Xi, Yi (Exploration and Development Research Institute, Petro-China Changqing Oil Field Company Ltd) | Ma, Jinfeng (National Engineering Laboratory for Exploration and Development of Low-Permeability Oil & Gas Fields)
Oil reservoirs are considered good storage structures for CO2 geological storage. With the right selection of candidate reservoir, injection of CO2 into tertiary and depleted oil reservoirs can result in enhanced oil recovery (EOR) and permanent sequestration of CO2 underground. The selection of candidate reservoirs for future CO2-EOR and storage projects mainly depends on storage potential evaluation. The aim of this work is to estimate the storage potential of CO2 stored in tertiary (CO2-EOR) and depleted oil reservoirs. In tertiary oil reservoirs, a method to estimate the geological CO2 storage capacity (CO2SC) in the reservoir during well open operations (EOR operations), which is a function of reservoir parameters, original geological reserves and oil volume factor is first built. In depleted oil reservoirs, a method to calculate the CO2SC in the reservoir during well shut down operations, which is based on the material balance method is proposed. In both cases, the methodology of storage capacity of CO2 dissolved in remaining oil, formation water and by mineral trapping is presented based on the model established by
Lu, Cong (Southwest Petroleum University) | Li, Junfeng (Southwest Petroleum University) | Luo, Yang (SINOPEC Southwest Oil & Gas field Company) | Chen, Chi (Southwest Petroleum University) | Xiao, Yongjun (Sichuan Changning Gas Development Co. Ltd) | Liu, Wang (Sichuan Changning Gas Development Co. Ltd) | Lu, Hongguang (Huayou Group Company Oilfied Chemistry Company of Southwest) | Guo, Jianchun (Southwest Petroleum University)
Temporary plugging during fracturing operation has become an efficient method to create complex fracture network in tight reservoirs with natural fractures. Accurate prediction of network propagation process plays a critical role in the plugging and fracturing parameters optimization. In this paper, the interaction between one single hydraulic fracture within temporary plugging segment and multiple natural fractures was simulated using a complex fracture development model. A new opening criterion for NF penetrated by non-orthogonal HF already was implemented to identify the dominate propagation direction of HF under plugging condition. Fracture displacements and induced stress field were determined by the three dimensional displacement discontinuity method, and the Gauss-Jordan and Levenberg-Marquardt methods were combined to handle the coupling between rock mechanics and fluid flow numerically. Numerical results demonstrate that the opening and development of NF are mainly dominated by its approaching angle and relative location. For a certain NF crossed by HF within plugging segment, HF tends to propagate along the relative upper part when the approaching angle is less than 90°, otherwise the lower part will be easier to open. The farther interaction position is away from HF tip, the easier NF with approaching angle less than 30° or larger than 150° can be open, and the outcome will be opposite if the approaching angle is larger than 45° or less than 135°. Higher approaching angle and plugging strength is necessary for expanding the position scope of NF that can be opened around HF. Under the impact of plugging, fluid pressure in HF plummets at the beginning of NF opening and keeps decreasing until NF extending for a certain distance or encountering secondary NFs. Fluid pressure drop occurs mainly in the unturned NF, together with the width of unturned NF is significantly lower than that of turned NF and HF. Sensitivity analysis shows that the main factors, such as geometry, aperture profile, and fluid pressure distribution, affecting the network progress under temporary plugging condition are the horizontal differential stress, NF position, approaching angle, plugging time, and plugging segment length. The simulation results provide critical insight into complex fracture propagation progress under temporary plugging condition, which should serve as guidelines for welling choosing and plugging optimization in temporary plugging fracturing.
Kamkong, Paphitchaya (PTTEP) | Karnjanamuntana, Thamaporn (PTTEP) | Prungkwanmuang, Weera (PTTEP) | Yingyuen, Jakkrich (PTTEP) | Oatwaree, Dejasarn (PTTEP) | Amornpiyapong, Nichakorn (PTTEP) | Khositchaisri, Patcharin (PTTEP) | Tivayanonda, Vartit (PTTEP) | Wongsuvapich, Dutkamon (PTTEP) | Tongsuk, Soraya (PTTEP)
Lunar field is a marginal gas field located in the Gulf of Thailand. A significant portion of reservoir sands is currently categorized as Additional Zones of Interest (AZI) which is not accounted in reserves. As for this kind of sand, the conventional petrophysical evaluation alone cannot certainly distinguish between hydrocarbon and water in the porous medium. The alternative method (dT LogR) for formation re-evaluation is therefore considered in attempt to reduce uncertainty in fluid classification and reveal hidden hydrocarbon potential from these AZIs.
There are 2 phases in verifying the validity of dT LogR method. Phase I: dT logR method (Ref.
Phase II: The production test data from perforated AZIs in phase I and the well correlation were then incorporated in dT LogR assisted log reinterpretation. Additional 13 gas-potential AZI candidates were identified for 2nd perforation test to prove the correctness of the recalibrated petrophysical model. The results showed success in model improvement of which its accuracy increased to 61% and no high water production was observed in any of them.
After using dT LogR method to assist petrophysical evaluation, a total of 469 metres of unperforated AZIs were reconsidered to be productive gas bearing formation. In other words, 22 BCF of gas reserves and 873 MSTB of condensate reserves from these upgraded AZIs were added. In addition, it is foreseen that the remaining AZIs of other platforms are to be further reevaluated and therefore improves the confidence in reserves booking and field development planning of Lunar Field.
In conclusion, the dT LogR method is a very useful tool for Lunar Field to significantly reduce uncertainty of fluid classification which in turn provides lots of benefits in gas field management adding immeasurable value to Lunar Field.
Luo, Ruilan (RIPED, PetroChina) | Yu, Jichen (RIPED, PetroChina) | Wan, Yujin (RIPED, PetroChina) | Liu, Xiaohua (RIPED, PetroChina) | Zhang, Lin (RIPED, PetroChina) | Mei, Qingyan (PetroChina Southwest Oil& Gas Company) | Zhao, Yi (PetroChina Southwest Oil& Gas Company) | Chen, Yingli (PetroChina Southwest Oil& Gas Company)
Ultra-deep naturally fractured tight sandstone gas reservoirs have the characteristics of tight matrix, natural fractures development, strong heterogeneity and complex gas-water relations. There is strong uncertainty of gas reserves estimation in the early stage for such reservoirs, which brings big challenge to the development design of gas fields. Taking Keshen gas field in Tarim basin as example, during the early development stage, the dynamic reserves were much less than those of proven geologic reserves. As results, the actual production performances are obviously different from those of conceptual design. What are the reasons? How to adjust the development program of gas field? Based on special core analysis, production performance analysis, gas reservoir engineering method, and numerical simulations, influencing factors on evaluation of dynamic reserves for ultra-deep fractured tight sanstone gas reservoirs are analyzed. The results show that rock pore compressibility, recovery percent of gas reserves, gas supply capacity of matrix rock, water invasion are the major factors affecting the evaluation of dynamic reserves. On the basis of above analysis, some suggestions are given for the evaluation of dynamic reserves in Ultra-deep fractured tight sandstone gas reservoirs. For this kind of reservoirs, it is reasonable to determine the gas production scale based on dynamic reserves instead of proven geological reserves.