Seismic attributes play an important role during reservoir characterization and three-dimensional (3D) lithofacies modeling by providing indirect insight of the subsurface. Using seismic attributes for such studies has always been challenging because it is difficult to determine a realistic relationship between hard data points (i.e., well information) and a 3D volume of seismic attributes. However, a probability-based approach for 3D seismic attribute calibration with well data provides better results of lithofacies modeling and spatial distribution of reservoir properties. This paper presents a probability-based seismic attribute calibration technique that has been described for 3D lithofacies modeling and distribution. This approach helps in subsurface reservoir characterization and provides a realistic lithofacies distribution model. This approach also helps reduce uncertainty of lithofacies prediction compared to conventional methods of simply using geostatistical algorithms.
Maintaining a stable borehole and optimizing drilling are still considered to be vital practice for the success of any hydrocarbon field development and planning. The present study deliberates a case study on the estimation of pore pressure and fracture gradient for the recently decommissioned Volve oil field at the North Sea. High resolution geophysical logs drilled through the reservoir formation of the studied field have been used to estimate the overburden, pore pressure, and fracture pressure. The well-known Eaton’s method and Matthews-Kelly’s tools were used for the estimation of pore pressure and fracture gradient, respectively. Estimated outputs were calibrated and validated with the available direct downhole measurements (formation pressure measurements, LOT/FIT). Further, shear failure gradient has been calculated using Mohr-Coulomb rock failure criterion to understand the wellbore stability issues in the studied field. Largely, the pore pressure in the reservoir formation is hydrostatic in nature, except the lower Cretaceous to upper Jurassic shales, which were found to be associated with mild overpressure regimes. This study is an attempt to assess the in-situ stress system of the Volve field if CO2 is injected for geological storage in near future.
With the current applications of CO2 in oil wells for enhanced oil recovery (EOR) and sequestration purposes, the dissolution of CO2 in the formation brine and the formation of carbonic acid is a major cause of cement damage. This degradation can lead to non-compliance with the functions of the cement as it changes compressive and shear bond strengths and porosity and permeability of cement. It becomes imperative to understand the degradation mechanism of cement and methods to reduce the damage such as the addition of special additives to improve the resistance of cement against acid attack. Hence, the primary objective of this study is to investigate the effects of hydroxyapatite on cement degradation.
To investigate the impacts of hydroxyapatite additive on oil well cement performance, two Class H cement slurry formulations (baseline/HS and hydroxyapatite containing cement/HHO) were compared after exposure to acidic environments. To evaluate the performance of the formulations, samples were prepared and aged in high-pressure high-temperature (HPHT) autoclave containing 2% brine saturated with mixed gas containing methane and carbon dioxide. Tests were performed at different temperatures (38 to 221°C), pressures (21 to 63 MPa) and CO2 concentrations (10 to 100%). After aging for 14 days at constant pressure and temperature, the samples were recovered and their bond and compressive strength, porosity and permeability were measured and compared with those of unaged samples.
The results demonstrated that adding hydroxyapatite limits carbonation. Baseline samples that do not contain hydroxyapatite carbonated and consequently their compressive strength, porosity, permeability, and shear bond strength significantly changed after aging while hydroxyapatite-containing samples displayed a limited change in their properties. However, hydroxyapatite-containing samples exhibit high permeability due to the formation of microcracks after exposure to carbonic acid at high temperature (221°C). The formation of microcracks could be attributed to thermal retrogression or other phenomena that cause the expansion of the cement.
This article sheds light on the application of hydroxyapatite as a cement additive to improve the carbonic acid resistance of oil well cement. It presents hydroxyapatite containing cement formulation that has acceptable slurry properties for field applications and better carbonic acid resistance compared to conventional cement.
Chullabrahm, Pattarapong (PTT Exploration and Production Public Company Ltd) | Saranyasoontorn, Korn (PTT Exploration and Production Public Company Ltd) | Svasti-xuto, Maythus (PTT Exploration and Production Public Company Ltd) | Trithipchatsakul, Chao (PTT Exploration and Production Public Company Ltd) | Sunderland, Damon (Arup Pty Ltd) | Ingvorsen, Peter (Arup Pty Ltd) | Madrigal, Sarah (Arup Pty Ltd) | McAndrew, Russell (Arup Pty Ltd)
This paper presents an integration of geology, geohazards, geophysics and geotechnical assessments for a design of an offshore gas production facility and an associated export pipeline. The gas field described in this paper is located off the North West coast of Australia in the Timor Sea in a water depth of approximately 130m.
Various resource development options were investigated during the Concept Select / pre-Front End Engineering Design (pre-FEED) phase of the project. These options included fixed and floating structures in the infield area and a 300km long export pipeline that ties into an existing gas trunkline connecting to an onshore processing plant.
To provide the necessary engineering due diligence to allow the project to progress further, several phases of geo-related investigations were undertaken to assess various geohazard challenges and foundation risks. Some of these challenges include a pipeline route traversing several steeply sloping seabed canyons, potential activation of turbidite sequences, and the presence of very soft carbonate sediments to calcarenite rock.
This paper describes these ground related challenges and how they were constrained through the geo-related investigations conducted, observations made and results obtained. Ground related challenges are described in two parts: Pre-FEED export pipeline routing reviews focusing on geohazard, geophysical and geotechnical considerations and ‘real time’ pipeline engineering Finite Element Analysis (FEA) performed offshore. Compared to normal practice, this non-standard offshore analysis allowed a preferred pipeline corridor to be identified during the survey with an informed understanding regarding feasibility and likely seabed intervention, thus optimising the field survey time and cost; and Staged acquisition and integration of infield geophysical and geotechnical data for developing high level assessments of foundation concepts.
Pre-FEED export pipeline routing reviews focusing on geohazard, geophysical and geotechnical considerations and ‘real time’ pipeline engineering Finite Element Analysis (FEA) performed offshore. Compared to normal practice, this non-standard offshore analysis allowed a preferred pipeline corridor to be identified during the survey with an informed understanding regarding feasibility and likely seabed intervention, thus optimising the field survey time and cost; and
Staged acquisition and integration of infield geophysical and geotechnical data for developing high level assessments of foundation concepts.
Key benefits of conducting an integrated approach to geo-related challenges on a complex site will also be presented in this paper.
The ‘Pseudo’ Dry Gas (PDG) subsea concept is being developed to dramatically improve the efficiency of subsea gas transportation by removing fluids at the earliest point of accumulation. The technology will increase the geographical reach from receiving gas terminals, allowing asset owners to prolong production life without the need for more expensive design solutions. This paper will provide an overview of the innovative technology, demonstrating that a 200 km plus tie back can be achieved, without compression.
Increasing the distance of subsea tie-backs increases the liquid inventory, with constraints on pipeline diameter for slug free flow. The PDG concept is based on a main gas line integrated with piggable gravity powered drain liquid removal unit and pumps (a smaller fluid line transports separated liquid). Multiple units are specified to drain liquids as they condense in the line, maintaining near dry service. Liquid free operation removes the constraint on pipeline diameter. Specification of a large diameter pipe (within installation limits) reduces backpressure on the wells, enhancing recovery. Minimum stable flow limits are removed, improving tail end recovery.
Current stranded gas development options (subsea compression, floating facilities, FLNG) generate a step change in costs which can make a project uneconomic. This is even more acute in mature and semi-mature basins where existing gas processing facilities / LNG terminals already exist offshore or onshore along with sunk costs from the exploration. A case study for a 185 km pseudo dry gas subsea tie-back to shore demonstrates the PDG concept feasibility. This result is used to argue that the PDG concept should be included in the suite of subsea processing options considered by Operators in early field development planning.
The selection of completion equipment for artificial lift string for any field in the oil and gas industry is important for the safe and reliable operations of such a field. This is critical to the management and overall profitability of the oil and gas asset, especially in areas where artificial lift is the predominant means of water injection and hydrocarbon production. This paper focuses on why it is important to understand the saline subsurface and the total dissolved solids (TDS) of the environment in which the artificial lift completion is to be deployed and its impact on equipment selection.
High concentration of corrosive components in the well fluid such as hydrogen sulfide, chlorine and total dissolved solids makes the well fluid conducive for electron migration. Such migration causes heavy corrosion, especially when dissimilar metals are used in artificial lift well completions. Carbon steel tubulars and casing are easily affected by such corrosive composition and leads to premature failure of artificial lift completions, which poses safety and operational issues. This type of environment is intense in electrical submersible pump completed wells because of the electromagnetic field generated by the current passing through the electrical cable of the pump system.
A combination of field and laboratory data gathering, and analysis was utilized to determine the effect of the aggressive components of the produced fluid on electrical submersible pumps assembly. The contributions of the high total dissolved solids in the conductivity of the well fluid, and in the electrochemical process for metal corrosion were analyzed. It was evident from both forms and approaches utilized in the analysis that well fluid becomes an electrolyte that provided the desired path for electron flow, which was enhanced by the magnetic field of the ESP system cable.
This paper highlights the integration of three approaches of geochemical analysis of well effluent, Anodic Index differential and tubular internal coating in corrosion prevention and electric submersible pump runlife elongation in wells with corrosive compositions including high total dissolved solids.
Significant challenges meeting together make Keshen gas field in Kucha foreland basin become unique from geosciences, engineering and economics points of view. These challenges generally link to harsh geography, super deep (>6500m TVD), thick conglomerates (up to 3000m), heterogeneous salt-gypsum laminations (up to 2000m), complex thrust-nappe structure, HTHP, and ultra-tight (matrix permeability < 0.1 md). This paper gives a comprehensive review how the geoengineering Long March assists to successfully develop this field.
A geoengineering team was established to persistently attack on this world-class championship with high-level planning since 2012. Specific research and development of engineering technologies and solutions for data acquisition, drilling, completion, stimulation, testing and production and studies were taking place in parallel. To ensure seamless integration from geosciences and engineering to operation, a five-year geoengineering study was proactively and progressively executed which includes four major steps with respective objectives including 1) understanding fluid distribution and producibility, 2) well production breakthrough and enhancement, 3) optimization of well stimulation and economics, and 4) optimization of field management including surprising sanding problem.
It was recognized three elements and their interactions are critical for production enhancement which are natural fracture (NF) characteristics, production controlling mechanism, and stimulation optimization under super deep, HPHT and extremely high stress conditions. The bottleneck for study was poor seismic quality due to super depth, pre-salt, and complex thrust-nappe structures. Hence the team established comprehensive methodologies with iterative improvements to overcome this bottleneck. Using regional structural geology, outcrops, cores, images and logs as inputs, structure restoration and geomechanics simulators were combined to perform structure restoration, paleo-stresses, and in-situ stresses and eventually 3D NF prediction. To understand production mechanism, analysis of geological and geomechanical factors, NF and stress relationships, single parameter and multiple variables, and transient and production performance were integrated. Big core studies were conducted to understand fracability, NF and hydraulic fracture (HF) interactions, and selections of HF fluids. Based upon, a stimulation optimization approach was implemented which included engineered completion designs, HF modeling and parametric studies, post-frac analysis and optimization, and time effects through high-resolution coupled geomechanics and reservoir simulation. All efforts with evolving knowledge were eventually developed as an interactive expert system to guide systematic stimulation optimization, sanding management and development optimization.
With increasing understanding of reservoir, and implementing innovative solutions, it was enabled to drill wells at optimal locations with less time, simplified well configuration, and less constraints on stimulation and production operations. By 2017, well construction time was reduced by half, natural productivity of wells was doubled, productivity after stimulation was tripled, and overall cost of wells was largely reduced. The success achieved would boost confidence and lighten on development of other challenging fields.
A software system based on deep neural network (DNN) technology was designed and trained to recognize fault lines in 2D seismic vertical sections, and fault surfaces in 3D seismic cubes. The system was successfully tested on public domain data from several basins in New Zealand. The paper describes the key components of the system and explains how they were designed. A relatively small size window is used to scan 2D seismic sections. Two DNNs identify if the window contains a fault and output the vector corresponding to the fault segment in the window. After scanning the entire section, a clustering algorithm is applied to group these vectors in separate clusters corresponding to the faults in the section. Finally, a linear regression algorithm calculates the fault lines – not always straight – in the section. Fault lines in successive 2D vertical sections of a 3D cube are associated to form fault surfaces. The training data set that was created to train the DNNs contains 120,000 examples. The validation test set has 30,000 examples. A special workflow and software were developed to generate these 150,000 labelled examples with a mix of synthetic and real data. The results obtained are quite satisfactory: the success rate exceeds 95% on the validation test set. The vector clustering algorithm properly handles crossing faults. The system is designed to quickly learn to correct mistakes highlighted by geophysicists, like patterns wrongly identified as faults, or missed faults. This system was trained to identify fault patterns in seismic data just based on examples. The concept can easily be expanded to recognize many other types of patterns such as structural or stratigraphic traps, horizons, and types of seismic facies. This fault detection software is the first step toward a machine learning-based system for automated structural interpretation of seismic data.
Qiu, Maoxin (CNPC Economics & Technology Research Institute) | Zhang, Huazhen (CNPC Economics & Technology Research Institute) | Zhang, Huanzhi (CNPC Economics & Technology Research Institute) | Liu, Jia (CNPC Economics & Technology Research Institute) | He, Yanqing (CNPC Economics & Technology Research Institute) | Wang, Lu (CNPC Economics & Technology Research Institute) | Zhang, Jiaming (CNPC Economics & Technology Research Institute)
The development of China's coalbed methane (CBM) industry is restricted by the complex geological conditions, unmatched technology and lack of development experience. To solve this problem, a case library covering typical CBM fields at home and abroad is established. Through data analysis and mining, the differences between domestic and foreign CBM fields are compared and the influence factors of CBM single well production were analyzed.
This study includes the data preparation of CBM fields, the establishment of the case library system, the establishment of data analysis model and the result analysis. The data of case library covers the geological conditions, development history, main technology and economy of CBM field. The case library is based on the MVC development idea and adopts the object-oriented method. The analysis of data includes correlation analysis of single well production and quantitative gap analysis.
The case library contains a number of typical case data, such as San Juan, Black warrior, Bowen, Surat, Qinshui, Hancheng, etc. The relevant parameters of different CBM fields can be quickly compared by using the case library. By mining the data such as coal rank, permeability, thickness, depth, gas content and proved reserves, the influence factors of single well production of CBM well are analyzed quantitatively. It is found that the thickness and permeability of coal seam have the greatest influence on single well production. Quantitative gap analysis shows that there is a large gap between the coal seam thickness, permeability, the gas drainage technology and well production improvement technology of domestic CBM fields compared with the foreign fields with the best development effect.
Through the application of CBM case library, data is analyzed and utilized effectively and data values are fully exploited. This study provides an effective way to analyze the gap of CBM in China and draw lessons from abroad.
Zhou, Chao (SINOPEC Research Institute of Petroleum Engineering, China University of Petroleum-Beijing) | Zhang, Tongyi (SINOPEC Research Institute of Petroleum Engineering) | Wu, Xiaodong (China University of Petroleum-Beijing) | Zhao, Fei (Engineering Technology Research Institute of Huabei Oilfield Company) | Xiong, Xiaofei (China University of Petroleum-Beijing)
Vortex drainage gas recovery is a new drainage gas recovery technology. However, its operating mechanism has not been figured out. Theoretical analysis of force condition of the liquid film in the wellbore vortex flow field is still lacking, and dynamic analysis method of the liquid film is not established. The objective of the proposed paper is to establish the liquid film dynamic analysis model and calculate the optimal helical angle of the vortex tool. Dynamic analysis of the liquid film in the wellbore vortex flow field is carried out on the basis of the flow pattern and force condition of the liquid film. Expression of each acting force is determined and the force equilibrium equation is obtained. Referring to the annular flow theory, friction coefficient and average thickness of the liquid film are calculated. Through derivation of the vertical resultant force equation of the liquid film, the optimal helical angle of the vortex tool is obtained. Then, vortex tools were designed and deployed in the wellbore of a gas well in field. Field study shows that the relative difference of the optimal helical angle obtained by liquid film dynamic analysis relative to that obtained by numerical simulation is less than 4%. The optimal helical angle calculated by the liquid film dynamic analysis model is reliable and provides guidance for the structure optimization of vortex tools. Optimal helical angle would increase with well depth decreases because of enhancement of fluid-carrying capability of the gas. The liquid film dynamic analysis model can reasonably explain the motion and force condition of the liquid phase in the wellbore vortex flow. Compared with the conventional annular flow field, vortex flow filed includes additional centrifugal force on the liquid film, which may benefit the upward motion of the liquid film. The liquid film dynamic analysis model in the wellbore vortex flow field and the formula for calculating the optimal helical angle of the vortex tool are established for the first time, whose results fill the gap in existing studies and have a guiding significance for optimization design and field application of vortex tools.