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Collaborating Authors
SPE Trinidad and Tobago Section Energy Resources Conference
Abstract The amount of time and effort required to access and integrate Subsurface data from multiple sources is significant. Using Advanced Data Analytics, mainly python, an integrated subsurface dashboard titled Hybrid Integrated Visualization Environment (HIVE) was created using Spotfire to empower the integrated Exploration, Development and Well Reservoir and Facilities Management (WRFM) subsurface teams in: Professionalizing data and knowledge management to have "one" version of the truth. Data consolidation and preparation to avoid repetitive manual work & Enhancing opportunity identification to optimize production and value The approach of subsurface data integration can be broken down into 4 major steps, namely: Step 1: Python programming was used to pre-process, restructure and create unified data frames. Use of python significantly reduces the time required to pre-process a diverse number of subsurface data sources consisting of static, dynamic reservoir models, log data, historical production & pressure data and wells & completion data to name a few. Step 2: - Standard diagnostic industry recognized diagnostic plots were automated using advanced analytic techniques in HIVE with the help of unified data frames. Step 3: HIVE was created to link various internal corporate data stores like pressure, temperature, rate data from PI System (stores real time measured data), Energy Components (EC) and Oil Field Manager (OFM) in real time. This was done to ensure that data from various petroleum engineering disciplines could now be visualized and analyzed in a structured manner to make integrated business decisions. Step 4: One of the key objectives of pursuing this initiative was to ensure that subsurface professionals in Shell Trinidad and Tobago were trained and upskilled in the use of python as well visualization tools like Spotfire and Power BI to ensure the maintenance and improvement of HIVE going forward. The development of HIVE has made it easier and more efficient to access and visualize subsurface data, which was extremely time consuming earlier while using older conventional techniques. Standard diagnostic plots and visuals were developed and are now used to drive integrated decision making, with key focus being water and sand production management from a production management perspective. Consequently, HIVE also drives enhanced integration between disciplines (Petrophysics, Petroleum Geology, Production Technology, Reservoir Engineering and Production operations) and departments (Developments, Upstream and Exploration). The petroleum industry has started to embrace the application of advanced data analytics in our day-to-day work. A successful application of these techniques results in transforming the ways of working by increasing efficiency, transparency and integration among teams.
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)
- Production and Well Operations (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Data mining (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (0.87)
Abstract Pseudo Dry Gas (PDG) technology is proposed as an alternative concept for transporting multiphase fluids (gas, condensate and water) for long deep-water subsea tieback developments (Ref 1 - OTC-28949-MS) (Ref 2 - IPTC-19440-MS). Using PDG technology, subsea pipeline networks can be extended to excess of 200 km total length and considerably reduce the backpressure on the wells. This allows improved recovery of the reserves and the ability to reach currently stranded fields, especially deep-water lower-pressure gas fields. The basis of the PDG system is to remove the liquid of the main pipeline system using Piggable Liquid Removal Units. With the removal of the liquid, the gravitational pressure losses in the system are eliminated allowing the pipeline to operate like a "Pseudo" Dry Gas system. The liquid phase is transported back to shore using a second smaller pipeline running in parallel to the main pipeline by means of subsea liquid pumps (Ref 3 - OTC-29332-MS). After techno-economic reports were completed for a known basin of stranded gas in the West of Shetland, an Oil and Gas Technology Centre (OGTC) experimental project was established to determine the operation performance of the element within the PDG technology with lowest Technology Readiness Level (TRL). Currently the liquid removal unit has a TRL2 and a TRL4 will be achieved after the experimental testing programme has been fully completed. This paper assesses the separation performance (Efficiency) of the Piggable Liquid Units or PDG unit. Previous Flow Assurance and Computational Fluid Dynamics (CFD) established expected efficiencies between 84-99% depending on the gas and liquid flow rates and other factors such as unit orientation, liquid type, operating pressure and temperature. Each PDG unit has two modules which allow for gas-liquid separation of the multiphase fluid in the pipeline. A PDG unit prototype has been built and a testing programme has been developed and undertaken in collaboration with Cranfield University (CU) using the large scale Inclinable Multip hase Flow Loop facilities. The testing programme has two test matrices: Matrix 1 which studies the performance of a single module of the PDG unit and Matrix 2 which investigates the efficienc y of the entire PDG unit (two separation modules). Matrix 1 of the testing programme allows to characterise the system varying the flow conditions (flow regime, liquid and gas flow rates), drop out liquid level and size, effect of sand and the inclination and orientation of the unit as would be expected once installed. This paper focuses on the results obtained from Matrix 1 testing programme and compares them with the initia l PDG unit estimated efficiency values used in previous studies to demonstrate the prove of concept of the PDG technology. The overall conclusion is that the performance of the PDG liquid removal unit is greater than the ones originally used in technology assessment reports.
Field Application of Software Model and Wellbore Strengthening Materials for Drilling Depleted Reservoirs and Mechanically Weak Formations in Gulf of Suez
Mohamed, Youssry Abd El-Aziz (EMEC) | Ahmed, Ragab Saber (EMEC) | Al-Zahry, Ayman Abd El-ghany (EMEC) | Moustafa, Amr Ismail (EMEC) | Elnashar, Radi Ahmed (Gulf of Suez Petroleum Co. / Dragon Oil Limited) | Salama, Ayman Salama (Gulf of Suez Petroleum Co. / Dragon Oil Limited) | Ouda, Abdalla Ahmed (Gulf of Suez Petroleum Co.) | Mohamed, Ahmed Hamdy (Gulf of Suez Petroleum Co.)
Abstract Drilling operations might require increasing mud weight beyond formation's fracture gradient margin which may lead to downhole losses into formation and other potential problems resulting in Non-Productive Time (NPT). This paper describes successful application of wellbore strengthening software (WSS) to simulate formations’ strengthening process by increasing Hoop Stress while drilling depleted reservoir sand or mechanically weak formations. The software model takes into consideration well design, basic rock properties and in-situ earth stresses. The paper also defines design of mud formula and lab procedures verifying the designed wellbore strengthening materials (WSM) blend and successful application in field. Design and selection of mud formula are main pillars of successful formation strengthening procedure to match with induced fractures width. Unlike other software models that use generic particle size distribution (PSD) data, software in this study takes into consideration PSD of specific batches of WSM to simulate wellbore strengthening process and recommend the optimum WSM blend, concentrations. Based on mud formula design from WSS, lab tests were conducted to verify concentrations and selection of WSM and accordingly formulas were applied successfully for complicated drilling operations. Static and dynamic formation strengthening techniques were applied successfully in multiple wells. Based on software results and recommendations, Techniques’ application managed to strengthen weak formations up to 121% of original fracture gradient, decreased section drilling time by 20% which resulted in drilling costs reduction by up to 24.2 %. As a result of this successful application in many critical wells, WSS results are now integral to operator's well plan to enhance wellbore pressure integrity of weak intervals, in following drilling operations. The presented study is based on an innovative approach to strengthen weak and depleted formations in critical drilling operations using exact PSD data of WSM batches, formation properties and customized software model, an optimum concentrations blend can be selected to strengthen wellbore and hence it can be customized for every application where optimum formation strengthening is required.
- Asia (1.00)
- North America > United States (0.93)
- Africa > Middle East > Egypt > Gulf of Suez (0.15)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock (0.69)
- North America > United States > California > Sacramento Basin > 2 Formation (0.99)
- Africa > Middle East > Egypt > Gulf of Suez > Gulf of Suez Basin > Zeit Formation (0.99)
- Africa > Middle East > Egypt > Gulf of Suez > Gulf of Suez Basin > South Gharib Formation (0.99)
- (4 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- (4 more...)
Abstract The Internet of Things has popularized the notion of a digital twin - a virtual representation of a physical system. There are substantial risks associated with designing a development plan for an oilfield and the industry has been making use of reservoir models - digital twins - to improve the decision-making process for many years. With an increase in the availability of computational resources, the industry is moving towards ensemble-based workflows to estimate risk in field development plans. In this paper, we demonstrate the use of an integrated ensemble-based approach to assess uncertainties in the reservoir models and quantify their impact on the decision-making process. An important feature of a digital twin is its ability to use sensor data to update the virtual model, more commonly known as history matching or data assimilation. We demonstrate how production data can be used to identify and constrain the uncertainties in the reservoir model. Production data is incorporated using Bayesian statistics and state-of-the-art supervised machine learning techniques to create an ensemble of models that capture the range of uncertainties in the reservoir model. This ensemble of calibrated models with an improved predictive ability provides a realistic assessment of the uncertainty associated with production forecasts. The ensemble-based approach is demonstrated through its application on an offshore oilfield located in the North Sea. The field is highly compartmentalized and has high structural uncertainty following the interpretation and depth conversion. An integrated cross-domain model is set up to incorporate typically ignored structural uncertainty in addition to the uncertainties and their dependencies in the dynamic parameters, including fault transmissibility, pore-volume, fluid contacts, saturation, and relative permeability endpoints, etc. Results from the history matched ensemble of models show a significa nt reduction in uncertainty in these parameters and the predicted production. An advantage of the proposed technique is that the automated, repeatable, and auditable ensemble-based workflow can assimilate the newly acquired measured data into the reservoir model at any time, keeping the model up-to-date and evergreen.
- Geology > Structural Geology > Fault (1.00)
- Geology > Rock Type > Sedimentary Rock (0.69)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 046 > Block 15/9 > Volve Field > Shetland Group > Åsgard Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 046 > Block 15/9 > Volve Field > Shetland Group > Svarte Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 046 > Block 15/9 > Volve Field > Shetland Group > Sleipner Formation (0.99)
- (18 more...)
Simulation Study Investigating the Impact of Carbon Dioxide Foam Fracturing Fluids on Proppant Transport
Elturki, Mukhtar (Missouri University of Science and Technology) | McElroy, Phillip D. (Texas Tech University) | Li, Dian (Texas Tech University) | Kablan, Ahmed (Misurata University) | Shaglouf, Hasan (Misurata University)
Abstract Production from unconventional reservoirs using hydraulic fractured wells has recently gained much attention due to its ability to increase recovery to high percentages. The placement of proppant in fractures plays a significant role in conductivity of fractures and well productivity. Here, we aimed to elucidate some basic concepts of the technique using FracPro simulator. FracPro and hydraulic fracturing consist of many design parameters that effect the results of the stimulation process. Of the many parameters that exist, three were focused on in this paper: proppant transport, the use of carbon dioxide (CO2) foam fracturing fluid, and the use of low specific weight versus higher specific weight. FracPro was also used to simulate the results of using a low specific gravity value of 1.9, a medium value of 2.7, and a high value of 3.5. The concentration of CO2 was also varied in each condition; concentrations of 30, 50, and 70% were used. After running investigating these scenarios, some unexpected results were obtained. Notably, a lower specific gravity should produce a longer effective proppant length; however, our data indicates shows the opposite.
- North America > United States > Kentucky (0.46)
- North America > United States > West Virginia (0.29)
An Intelligent Completion and Artificial Lift Technology to Develop Large Carbonate Reservoirs: Novel Completion and Zonal Water Injection via Remote Control Methods to Develop Horizontal Wells
Fu, Jin (CNPC Engineering Technologies R&D Company Ltd.) | Wang, Xi (CNPC Engineering Technologies R&D Company Ltd.) | Yang, Guobin (CNPC Engineering Technologies R&D Company Ltd.) | Zhang, Shunyuan (CNPC Engineering Technologies R&D Company Ltd.) | Chen, Chen (CNPC Engineering Technologies R&D Company Ltd.) | Han, Haochen (CNPC Engineering Technologies R&D Company Ltd.)
Abstract There are several large carbonate reservoirs that have drawn great attention of researchers in recent years. After optimization of drilling technologies, how to deploy artificial lift technologies to develop them more efficiently is another concern. Conventional zonal water injection technologies require repetitive operation with wirelines and cables, causing extensive tests and low efficiency. However, an intelligent zonal water injection string consisting of several preset cable packers, water injection pressure gauges, formation pressure gauges and downhole flow meters has simply optimized water injection parameters and efficiently developed all reservoirs in some China's mature oilfields, especially when the string is integrated with remote monitoring and control methodologies. With the rapid development of horizontal drilling and extended reach well drilling technologies, borehole conditions are becoming more and more complicated, which has brought more challenges to water adsorption testing of horizontal intervals and deployment of zonal water injection instruments. Compared with vertical wells, the water adsorption test and string running are more challenging for horizontal wells, in which we are faced by many a problem during zonal water injection, such as competitive slack off and tight pull, excessive or inadequate water injection, complicated operation process. Besides, well deviation, dog leg and horizontal section length shall be all taken into consideration during zonal water injection for horizontal wells. Therefore, novel strings and tools should be deployed. Now tight pull, slack off and long operation periods are common problems during zonal water injection of horizontal intervals. After dedicated research, a set of wireless intelligent water injection strings for horizontal wells has been invented. Based on pressure pulse water distribution technique, the water injection string is eligible for 32-stage adjustment, so one strip may accomplish testing, adjusting, injection, measurement and downhole data collection, in addition to automatic error correction during water injection. The field trial shows that this novel string may be tripped in and out smoothly, packers are set securely and released easily, in order to adjust opening of each water injection nozzle in the ground, with an error of no more than ±10%. Therefore, the novel completion and water zonal water injection string is capable of injecting water precisely via remote control methods. The wireless intelligent water injection string for horizontal wells that combines testing, adjusting, injection, measuring and data collection in one trip provides us with many downhole data, such as pressure, flow rate, temperature and so on. Therefore, water injection volume for each zone is monitored and controlled down hole. This technology is applicable for both horizontal and vertical wells that require zonal water injection.
- Asia > China (1.00)
- North America > United States > Texas (0.29)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > New Mexico > Permian Basin > Wolfcamp Formation (0.99)
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
- (2 more...)
Abstract Surfactant flooding has long been considered a reliable solution for enhanced oil recovery, either by reducing oil-water interfacial tension (IFT) or through wettability alteration. This paper reveals the effect that reduced IFT has on capillary trapping in heterogeneous reservoirs. This effect is investigated through various numerical experiments on different simulation models where rock capillary pressure is assumed to scale with IFT. Capillary contrast on the scale of a few centimeters to a few tens of meters is reduced in the presence of surfactants. This reduction in IFT, under very specific circumstances, creates favorable conditions for increased or accelerated hydrocarbon production from mixed-wet reservoirs. The focus of this study is to ascertain the effectiveness of surfactant flooding in mixed-wet reservoirs. Simulation studies of different mechanisms which are believed to occur in mixed-wet reservoirs are presented. Simulation results indicate the promising effect of surfactant flooding on oil recovery, depending on the type of reservoir. Detailed fine-scale simulation studies are carried out with representative relative permeability and imbibition capillary pressure curves from mixed-wet cores. By designing and selecting a series of surfactants to lower the IFT to the range of 10dynes/cm, a recovery of 10 to 20% of the original oil-in-place is technically and economically feasible. The efficiency of surfactant flooding is investigated through sensitivity scenarios on formation rock/fluid parameters, including permeability, interfacial tension, rate flow, etc. Geological heterogeneity (layering and heterogeneous inclusions), imbibition capillary pressure curves, viscous/capillary balance (Nc), and gravitational forces were all found to have an impact on recovery by surfactant flooding. Numerical model dimensions, permeability, IFT, density contrast between oil and water, and injection flow rates were found to be the critical parameters influencing simulation results. Gravity segregation, typically ignored in earlier studies, was found to have a significant effect on reservoir performance. Two different numerical models, with and without impermeable shale streaks, were used to capture the gravity segregation effect. The results revealed that the reduction in interfacial tension helps gravity to segregate oil and water, ultimately resulting in improved oil recovery. Moreover, results from the numerical simulation studies revealed that either an inexpensive or a good quality surfactant at low concentration can be used to obtain the same enhanced oil recovery. The effect of change in oil relative permeability curvature, due to reduced interfacial tension, also revealed a reduction in the remaining oil saturation with an increase in the capillary number.
- Europe (0.46)
- North America (0.28)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract Frequent rod failures still occur in Progressive Cavity Pumped (PCP) wells with high dog-leg severities although they are fitted with adequate rod centralization. This results in well downtime and production deferrals. Offshore workovers are expensive and significantly affect operating cost (OPEX) of the operator. This study sought to evaluate the potential benefits of Electrica l Submersible Progressive Cavity Pumps (ESPCP) as an economic alternative for highly deviated wells in the offshore field in Trinidad. In this theoretical study, a screening criterion was established and four (4) candidates, all produced by surface driven PCPs, were selected. Models of ESPCP systems were developed using industry standard Progressive Cavity Pump software, parameters from the original PCP models as well as actual field well tests and production data. An economic evaluation, which integrated oil price and production rate sensitivities, was conducted using field data, including field reservoir characteristics and past well performance. The ESPCP model results suggest a cumulative increase of 567 BOPD is expected for all four wells. Using an oil price of US $45 per barrel, the analysis was conducted on all wells targeted for ESPCP conversion. Assuming a P50 oil rate, sensitivities were run to establish the minimum oil price for the project to be economically feasible. The operator's project economic success criteria were :(1) pay-out period of <2 years and (2) NPV of > US $0.15 Million considering a ten (10) year project. An integrated sensitivity analysis was performed for the entire project with varying expected production increases and fluctuating global oil prices. The simulations identified that the project will be uneconomic at a global oil price of US $20/bbl. Assuming a project life of 10 years and based on the expected production increase, the project is massively profitable, yielding an expected NPV of US $9.3 Million at US $45 per barrel with expected pay-out times between 0.63-1.8 years with investment of US $4 Million. Additional benefits anticipated include, increased well uptime and the corresponding reduction in workover costs. Another opportunity that results from the conversion to ESPCP, is the possibility of lowering the pump in the wellbore, thereby increasing the well producing life and increasing the recoverable reserves. Installation of ESPCPs, in theory, can be an economic success in an area where surface driven PCP experiences repetitive rod failures, leading to production deferrals and workover. Additionally, lowering the pump in the wellbore may be possible, thereby increasing the well producing life and increasing recoverable reserves which would not have been possible using traditional artificial lift methods.
- North America > Trinidad and Tobago > Trinidad (0.47)
- North America > United States > Texas > Dawson County (0.24)
- South America > Colombia > Santander Department > Middle Magdalena Basin > La Cira Infantas Field (0.99)
- North America > Trinidad and Tobago > Trinidad > Siparia > Gulf of Paria > Soldado Field (0.99)
- North America > Trinidad and Tobago > Trinidad Field (0.97)
Abstract Objectives/Scope Downhole Annular Barrier (DAB) systems employed in intervention can correct integrity and conformance control issues during well lifecycle, extending the productive term in a safe and costeffective manner. These emergent wireline technologies come with unique challenges for logistics, quality control, and engineering, but can also provide solutions to difficult problems, with high value to spend ratio, in the non-rig intervention sector. The paper will review one such successful intervention, completed offshore Trinidad W.I., in a gas well presenting long term Sustained Casing Pressure (SCP). The desired end state of the well was A-Annulus at 0 psi SCP, which would return the well to a safe state and permit a planned infrastructure project to move ahead. Methods, Procedures, Process Operational objective was isolation of the casing annulus pressure from the source by injecting epoxy into the annular space at depth, forming a 360-degree pressure barrier. The project can be broken down into three main sections. The paper and presentation will address each section with its specific challenges, learnings, and outcomes: Onshore Epoxy and Tool Preparation Each Downhole Annular Barrier job employs a custom recipe epoxy suited to the planned logistics timing and expected bottomhole conditions. Quality control of the epoxy recipe and mixing process as well as temperature control of the batch after mixing is key to the sealing properties of the final epoxy plug. • An Epoxy Lab and Mixing Station was dismantled, air freighted, and reconstituted in Trinidad near to the field operations port. Special insulated offshore CCU were built to transport and contain filled epoxy canisters while maintaining low temperature requirements (near to 0 deg C for up to 30 days). • Build and System Integration Testing (SIT) of the downhole system (anchoring, stroking, hydraulic testing, perforation, and injection) with the electric line system (conveyance, telemetry, power). Offshore Job Execution The DAB system employed is designed to complete multiple operations in a single trip into the well, including perforating and high-pressure epoxy injection, with precise position control and monitoring. This is made possible with the multi-function modular tool. The operation was dynamic by design and contingencies were implemented based on the well response. Multiple epoxy annular plugs were placed into the A Annulus at depth, with high pressure injection. Results, Observations, Conclusions Well Response and Assessment Utilizing advanced annular surface monitoring technology and PvT analysis, precise assessment of the annulus pressure build was recorded throughout the operation. Once the project criteria were met, the operation was successfully concluded.
Abstract This paper presents case studies of how produced water salinity data was used to transform the performance of two oil producing fields in Nigeria. Produced water salinity data was used to improve Field B’s reservoir simulation history match, generate infill drilling targets, and reinstate Field C’s oil production. A reservoir simulation study was unable to history match the water cut in 3 production wells in Field B. Water salinity data enabled the asset team to estimate the arrival time of injected sea water at each production well in oil field B. This improved the reservoir simulation history match, increased model confidence, and validated the simulation model for the placement of infill drilling targets. The asset team also gained additional insight on the existing water flood performance, transformed the water flooding strategy, and added 9.6 MMSTB oil reserves. The asset team at Field C was unable to recover oil production from a well after it died suddenly. The team evaluated water salinity data, which suggested scale build up in the well, and completed a bottom-hole camera survey to prove the diagnosis. This justified a scale clean-out workover, and added 5000 barrels per day of oil production. A case study of how injection tracer data was used to characterise a water injection short circuit in Field D is also presented. Methods of using produced water salinity and injection tracer data to manage base production and add significant value to petroleum fields are presented. Produced water salinity and injection tracer data also simplify water injection connectivity evaluations, and can be used to justify test pipeline and test separator installation for data acquisition.
- Europe (1.00)
- Africa > Nigeria (1.00)
- North America > United States > Texas (0.46)
- North America > United States > Mississippi > Marion County (0.24)
- North America > United States > Mississippi > Improve Field (0.99)
- Asia > India > Andhra Pradesh > Bay of Bengal > Krishna-Godavari Basin > Block KGD6 > Dhirubhai Field > D1 Well (0.99)
- Africa > Nigeria > Gulf of Guinea > Bight of Bonny > Niger Delta > Niger Delta Basin > OML 126 > Nda Field (0.98)
- (2 more...)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Management > Asset and Portfolio Management (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)