This paper has an objective of identifying the nature of formation fluid from an extreme tight fractured reservoir. A good understanding of petrophysical properties of the reservoir rock as well as the fluid it contains constitutes a real challenge for tight reservoirs, that are the most common unconventional sources of hydrocarbons. The front-line characterization mean is the Wireline logging which comes directly after drilling the well or while drilling, knowing that for low to extreme low porosity-permeability reservoirs any attempt of conventional well testing will not bring any added value not rather than a confirmation of reservoir tightness. A tailored workflow was adopted to design the most appropriate formation testing module, select the best depths for fluid sampling, and distinguish hydrocarbon from water bearing intervals. This workflow involves ultrasonic and Electric Borehole Images in combination with Sonic Scanner for natural fractures detection, localization and characterization, integrating Dielectric recording and processing for petrophysical evaluation, then Formation Testing was carried out for fluid identification and sampling. The use of borehole electric and sonic imager coupled with advanced sonic acquisition helped not only to identify the natural fractures depths, but also the nature of these fractures. This integration was used for selecting the sampling station.
Taha, Taha (Emerson Automation Solutions) | Ward, Paul (Emerson Automation Solutions) | Peacock, Gavin (Emerson Automation Solutions) | Heritage, John (Emerson Automation Solutions) | Bordas, Rafel (Emerson Automation Solutions) | Aslam, Usman (Emerson Automation Solutions) | Walsh, Steve (Emerson Automation Solutions) | Hammersley, Richard (Emerson Automation Solutions) | Gringarten, Emmanuel (Emerson Automation Solutions)
This paper presents a case study in 4D seismic history matching using an automated, ensemble-based workflow that tightly integrates the static and dynamic domains. Subsurface uncertainties, captured at every stage of the interpretative and modelling process, are used as inputs within a repeatable workflow. By adjusting these inputs, an ensemble of models is created, and their likelihoods constrained by observations within an iterative loop. The result is multiple realizations of calibrated models that are consistent with the underlying geology, the observed production data, the seismic signature of the reservoir and its fluids. It is effectively a digital twin of the reservoir with an improved predictive ability that provides a realistic assessment of uncertainty associated with production forecasts.
The example used in this study is a synthetic 3D model mimicking a real North Sea field. Data assimilation is conducted using an Ensemble Smoother with multiple data assimilations (ES-MDA). This paper has a significant focus on seismic data, with the corresponding result vector generated via a petro-elastic model. 4D seismic data proves to be a key additional source of measurement data with a unique volumetric distribution creating a coherent predictive model. This allows recovery of the underlying geological features and more accurately models the uncertainty in predicted production than was possible by matching production data alone.
A significant advantage of this approach is the ability to utilize simultaneously multiple types of measurement data including production, RFT, PLT and 4D seismic. Newly acquired observations can be rapidly accommodated which is often critical as the value of most interventions is reduced by delay.
Wei, Chenji (Research Institute of Petroleum Exploration and Development, CNPC) | Zheng, Jie (Research Institute of Petroleum Exploration and Development, CNPC) | Ouyang, Xiaohu (China Petroleum Pipeline Engineering Co., Ltd, CNPC) | Ding, Yutao (China National Oil and Gas Exploration and Development Company Ltd. CNPC) | Ding, Mingming (China National Oil and Gas Exploration and Development Company Ltd. CNPC) | Lin, Shiyao (China National Oil and Gas Exploration and Development Company Ltd. CNPC) | Song, Hongqing (University of Science and Technology Beijing)
Understanding the heterogeneity is critical for a successful water injection in a carbonate reservoir. Thief zone is one of the most obvious forms of heterogeneity, which indicates the thin layer with higher permeability compared to the average reservoir permeability. The existence of thief zone results in earlier water breakthrough and faster water cut increase, which then lead to lower sweep efficiency and smaller recovery factor. Therefore, determining the distribution of thief zone and its impact towards production, and proposing a corresponding development plan are very important.
In this paper, a novel method is established to determine the thief zone distribution based on dynamic surveillance data. A new index is proposed as the relative contribution index to characterize the relative contribution of a certain layer, which is fundamental for thief zone determination. In addition, effect on water flooding development of thief zone's location is studied by experimental and theoretical analysis. The changes of water cut and production rate are analyzed under different conditions such as location of the thief zone, injection rate, and variogram. Finally, optimized development strategy is proposed to deal with the existence of thief zone.
Distribution of thief zone is characterized based on the proposed method, which indicates that thief zone development has intimate relationship with depositional facies and diagenesis. Experimental and theoretical analysis results show that the present model considering stratified water-flood is consistent with the experimental results. The water displacement effect is the best when the thief zone is located in the upper reservoir. This paper also points out the optimal adjustment period for water shutoff and profile control of the reservoir with thief zones. In addition, the greater the injection rate, the faster the water cut increase. Furthermore, the smaller the variogram, the slower the water cut increase, and the later the water breakthrough time.
This study provides a method to characterize thief zone, which can be used as a reference for similar oilfield development. In addition, it provides a quick and reasonable guide in the later adjustment of water flooding development of carbonate reservoirs with thief zones.
Dong, Xuemei (Research Institute of Geophysical, Research Institute of Exploration and Development, PetroChina Xingjiang Oilfield Company) | Zhang, Ting (Surignan Operating Company, PetroChina Changqing Oilfield Company) | Yao, Weijiang (Research Institute of Geophysical, Research Institute of Exploration and Development, PetroChina Xingjiang Oilfield Company) | Hu, Tingting (Research Institute of Geophysical, Research Institute of Exploration and Development, PetroChina Xingjiang Oilfield Company) | Li, Jing (Research Institute of Geophysical, Research Institute of Exploration and Development, PetroChina Xingjiang Oilfield Company) | Jia, Chunming (Research Institute of Geophysical, Research Institute of Exploration and Development, PetroChina Xingjiang Oilfield Company) | Guan, Jian (Research Institute of Geophysical, Research Institute of Exploration and Development, PetroChina Xingjiang Oilfield Company)
Pore structure is of great importance in tight reservoirs identification and validation evaluation, especially for formations with developed fractured. However, the conventional pore structure evaluation method based on nuclear magnetic resonance (NMR) logging lost its role. This is because the fractures with width lower than 2mm did not have response in the NMR T2 spectrum. Whereas the porosity spectrum, which extracted from the FMI data, was considered to be effective in fractured reservoir pore structure evaluation. In this study, to quantitatively characterize tight glutenite reservoir pore structure in the Jiamuhe Formation in northwest margin of Junggar Basin, northwest China, 90 core samples were drilled for lab mercury injection capillary pressure (MICP) measurement, and the XRMI data (acquired by the Halliburton and be similar with FMI) was processed to acquire the porosity spectrum.
Pavlov, Dmitry (Sakhalin Energy Investment Company Ltd.) | Fedorov, Nikolay (Sakhalin Energy Investment Company Ltd.) | Timofeeva, Olga (Sakhalin Energy Investment Company Ltd.) | Vasiliev, Anton (Sakhalin Energy Investment Company Ltd.)
This paper summarizes the results of 3 years collaborative efforts of the Geophysicist, Production Geologist and Reservoir Engineers from the Astokh Development Team and a Geochemist from the LNG plant laboratory on integration of reservoir surveillance and reservoir modelling.
In period 2015 – 2018 a large bulk of geological and field development data was collected in Astokh field, in particular: cased and open hole logs, core, open hole pressure measurements, flowing and closed-in bottom hole pressures, well test data, new 4D seismic surveys (2015, 2018), fluid samples. Since 2016, essential progress was made in oil fingerprinting for oil production allocation in Astokh field. Simultaneously, the need for update of static and dynamic models was matured upon gaining experience in dynamic model history matching to field operational data (rates, pressures, well intervention results). In other words, the need in update of geological architecture of the Astokh reservoir model was matured upon reaching critical mass of new data and experience. To revise well correlation, it was decided to combine different sorts of data, in particular seismic, well logs and core data and reservoir pressures. Different pressure regimes were identified for 3 layers within XXI reservoir. Pressure transient surveys were used for identification of geological boundaries where it's possible and this data was also incorporated into the model. Oil fingerprinting data was used for identification of different layers and compartments. Integration of pressure and oil geochemistry data allowed to identify inter-reservoir cross-flows caused by pressure differential. Based on all collected data, sedimentology model and reservoir correlation were updated based on sequential stratigraphy. As a result, a new static model of main Astokh reservoirs was built, incorporating clinoform architecture for layers XXI-1' and XXI-2. To check a new concept of geological architecture material balance model was used and matched to field data
Integration of geological and field operational data provided a key to more advanced reservoir management and development strategy optimization. Based on updated reservoir model, new potential drilling targets were identified. Also, with new well correlation, water flood optimization via management of voidage replacement ratio was proposed. The completed work suggests essential improvement in reservoir modelling process by inclusion of various well and reservoir surveillance data.
The paper consists of the following sections: Introduction Field geology Field development history Scope of work complete and main results Proposed well correlation update for XXI-1' and XXI-2 layers Integration of well logs, pressure and fluid analysis data Connectivity between layers XXI-S, XXI-1' and XXI-2 Integration of pressure and oil fingerprinting data Connectivity within layers XXI-S, XXI-1' and XXI-2 Results of pressure interference tests Testing of new well correlation concept in material balance model Proposed reservoir correlation updated based on seismic data New geological concept New depositional model Integration of core data Changes in reservoir architecture Conclusion Main results and impact on field development
Field development history
Scope of work complete and main results
Proposed well correlation update for XXI-1' and XXI-2 layers
Integration of well logs, pressure and fluid analysis data
Connectivity between layers XXI-S, XXI-1' and XXI-2
Integration of pressure and oil fingerprinting data
Connectivity within layers XXI-S, XXI-1' and XXI-2
Results of pressure interference tests
Testing of new well correlation concept in material balance model
Proposed reservoir correlation updated based on seismic data
New geological concept
New depositional model
Integration of core data
Changes in reservoir architecture
Main results and impact on field development
The FPSO Kaombo Norte came on stream on July 27 2018, offshore Angola. When both its FPSOs will be at plateau, the biggest deep offshore project in Angola will account for 10% of the country's production. Kaombo reserves are spread over an 800-square-kilometer area. The development stands out for its subsea network size with more than 270 kilometers of pipeline on the seabed between 1500-2000 m water depth, including subsea production wells more than 25 km away from the production facility. Producing complex fluids within such a challenging environment required demanding thermal performance of the overall subsea asset with both the problematics of steady-state arrival temperature and cooldown. To do so, the transient thermal signature of every subsea component has been evaluated and correlated into a dynamic flow simulation to verify the integrity and therefore, safety of the system.
A unique design of subsea equipment aims to cover a large range of reservoir conditions. In order to tackle both risks of wax deposit during production and hydrates plug during restart, the whole system was designed to have a very low U-value and stringent cooldown requirements. A dedicated focus on having an extremely low U-value for the Pipe-in-Pipe (PiP) system enables to improve the global thermal performance. The accurate thermal performance predictions from computer modelling were firstly validated during the engineering phase with a full scale test. Eventually an in-situ thermal test was performed a few days before the first-oil to assess the as-built performance of the full subsea network. A well prepared procedure allowed to characterize precisely the subsea system U-value in addition to evaluate the cooldown time of critical components, after installation. The error band was properly assessed to take into account the difficulties of performing such remote measurements from an FPSO.
The different elements of the qualification procedure were successful, validating the demanding thermal requirement of the subsea system. The validation of the thermal performance of the flowline was fully achieved. Detailed analysis of the test results was performed in order to define precisely the U-value in operations. The as-built performance verification, including all elements of the complex subsea network, allowed to validate the optimized operating envelopes of the production system.
A detailed qualification process was conducted in order to fulfill one of the most challenging thermal requirements for a subsea development. Thanks to the precise prediction of the flowline insulation performance, the different reservoir conditions are safely handled. The operating envelope of the production system is finally optimized with the confidence from as-built performances confirmation.
In the oil sector, TOTAL should become the "low cost champion". This is presently our main challenge as mentioned by our CEO in the strategical document "One Total, our ambition". A key to succeed in a mature field such as PNGF North (CONGO) is to convert gas lifted wells into ESP activated wells. The ATEX VSD innovation consists of having the electrical module of an ESP activated well located in hazardous area, avoiding high costs that would result from a platform extension (for an electrical room). This innovation was designed by TOTAL E&P CONGO (TEPC) and installed on the YAF2 platform (YANGA field) in June 2018 has enabled to increase the production of the YAM254 well by 250% and its operational efficiency by 25 points. This innovation, which would not be possible without the close cooperation between headquarters and TEPC, could be extended to the entire TEPC subsidiary and thus open doors for new development opportunities for TOTAL brown fields.
In a deepwater environment, production fluid conditions have to satisfy complex requirements to flow smoothly to the production facilities on the FPSO. Flow assurance specialists work at turning these constraints into operating guidelines. This allows to close the gap between reservoir conditions, optimized design of the subsea network, topsides processing capabilities and operability requirements.
In the context of Kaombo, offshore Angola (Block 32), the wide range of reservoir conditions and fluids plus the extreme specificities of the subsea network called for an innovative approach with the following objectives: Empower the operator with a visual decision tool for normal and unplanned operations of the subsea system Promote collaboration between production, flow assurance & geoscience teams to reach an efficient decision, and minimize production shortfalls Allow a design robust enough to tackle geosciences uncertainties Optimize subsea design margins
Empower the operator with a visual decision tool for normal and unplanned operations of the subsea system
Promote collaboration between production, flow assurance & geoscience teams to reach an efficient decision, and minimize production shortfalls
Allow a design robust enough to tackle geosciences uncertainties
Optimize subsea design margins
This new approach, the "Visual Operating Envelopes", aims at explicitly and visually defining the operating limitations of the subsea production loops in a multi-parameters environment: A multi-dimensions map, function of the six main parameters (basically liquid and gas-lift flowrates, water and gas contents, reservoirs pressure and temperature) influencing multiphase flow into pipeline is hence created to evaluate the six main operating constraints (thermal and hydraulic turndown rates, wells eruptivity, maximum flowrates) for the full range of Kaombo fields.
This "operating envelope" tool can then define the minimum and maximum recommended flowrates for different operating conditions based on the following safe criteria: Arrival temperature above the Wax Appearance Temperature No hydrates risk during preservation No severe slugging effect Production below the flowline design flowrate Velocity below the erosional velocity
Arrival temperature above the Wax Appearance Temperature
No hydrates risk during preservation
No severe slugging effect
Production below the flowline design flowrate
Velocity below the erosional velocity
In addition, the optimized gas lift flowrate is directly accessible, and the pressure available at every wellhead is compared to the backpressure associated to the operating point to assess the eruptivity of the wells.
By having previously defined an overall operating envelope, it is extremely easy to evaluate quickly the impact of new operating conditions (due to degraded operating conditions, changes in reservoir parameters, modifications in the drilling and wells startup sequence), which makes this new approach very powerful and versatile. It also contributes to the definition of the production forecast during operation phase integrating reservoir depletion and available gas lift rate.
Instead of relying on specific simulations for a limited number of cases, this innovative method defines a new approach where operating parameters are evaluated from the start, and boundaries are clearly identified, thus allowing to build a sound production profile for an extensive range of operating conditions. By doing so, system knowledge is improved, bottleneck conditions are anticipated, operators, flow assurance and geoscience teams are able to tightly collaborate and take smarter decisions together, resulting in more production. Eventually the method applied to a multiphase pipeline is actually transposable to every problem involving multi-dimensional inputs with combined constraints.
It is often stated that necessity is the mother of invention. Never is this proverb more relevant than in the offshore oil and gas environment we currently operate in where real step changes leading to reduced capital and operational expenditure opportunities are sought and embraced by field operators. This paper discusses the pre-job planning, field execution and lessons learned from one such technology that challenged conventional thinking of sand faced completion, casedhole completion and well integrity to successfully deliver a single-trip, interventionless, sand control completion in deepwater Bonga Field, located on the continental slope of the Niger Delta.
Convention dictates that the vast majority of offshore completions be run in two and sometimes three trips which routinely takes in excess of eight to ten days to deploy. Given the day rate of high specification rigs capable of drilling in deep water environments, the ability to reduce this time was deemed paramount to the economics of the project. Utilizing a collaborative approach to initial concept design, risk assessment, extensive testing and contingency planning at component and system level, a single-trip, interventionless, sand control completion system was designed and successfully installed. This paper describes the completion architecture, operational sequence and challenges leading to the installation of an interventionless completion.
A clearly defined set of deliverables and design principles were drawn up to guide the direction of the project including: successfully deploying the upper and lower completion in one trip, and testing all barriers. Adopting a simple, low risk and high reward design, meeting clients well barrier requirements and utilizing proven cost-effective technology are examples of design principles used. The system was tested and evolved through a number of iterations in an onshore trial well environment on a number of occasions leading to the first successful deployment completed in the second half of 2018, resulting in an average completion installation time of 5 days, versus the average 10 days for deploying multi-trip completions. Details of the successful installations, lessons learned, along with planned future activity are outlined within the body of this paper. While several of the components incorporated in the single-trip system had been run previously in isolation, this paper also discusses the steps taken to facilitate the first full-system approach to the application of radio frequency identification (RFID) enabled tools in the first single-trip, interventionless sand control completion system. Several components within the completion have been equipped with this technology including a multi-cycle ball valve, wire wrapped screens fitted with inflow control device (ICD), remote operated sliding sleeve for annular fluid displacement.
The FPSO Kaombo Norte came on stream on July 27 2018, offshore Angola. When both its FPSOs will be at plateau, the biggest deep offshore project in Angola will account for 10% of the country's production. Kaombo reserves are spread over an 800-square-kilometer area. The development stands out for its subsea network size with more than 270 kilometers of pipeline on the seabed between 1500-2000m water depth, including subsea production wells more than 25km away from the production facility.
During the project phase, measures have been taken in order to standardize the subsea design overall including the thermal requirements. By necessity the insulation design of the subsea component is driven by the most stringent part of the development which is then applied throughout the complete system on Kaombo. This inevitably infers that certain parts of the system operate with a built-in margin regarding thermal performance. With an overall objective to optimize the OPEX the use of this margin on some assets generates added-value in the operational phase by reducing production shortfalls through reducing the number of preservations undertaken during life of field.
In order to improve the overall preservation sequence, crude abilities to delay hydrates formation and/or to transport hydrates have been studied on the coldest fields. It was found that studied crudes present interesting properties to delay hydrates formation. These tests have been performed with crude samples in lab conditions in order to assess the temperature and pressure when hydrates start to form. The results indicate that it is possible to extend the waiting period (i.e. time before launching preservation) well inside the hydrate thermodynamic zone and operating "safety" zones have been defined depending of the actual temperature and pressure.
An optimized preservation sequence postponing the decision point to restart or preserve was finally implemented thanks to:
An accurate knowledge of the full system thermal performance especially including the weak links The study of crude properties for the most penalizing fields vs. hydrates plug risk
An accurate knowledge of the full system thermal performance especially including the weak links
The study of crude properties for the most penalizing fields vs. hydrates plug risk
The methodology implemented is today already field proven and application of the extended waiting period was performed allowing reduction of shortfalls and smooth restart. A significant impact is expected for the full life of the field.