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.
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.
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.
The course will discuss the Huff-n-Puff gas EOR process specifically, but will also give a background in the relevant fundamentals of gas EOR methods (miscibility, vaporization, and displacement). Alternative EOR methods will also be discussed. The course is introduced by an industrywide summary of ongoing gas EOR projects in North American unconventionals.
Reservoir evaluation of source rock is still a challenge because the geochemical assessment of the kerogen content is complicated and time consuming. Existing traditional methods to characterize kerogen involves the removal of inorganic minerals which is a critical preliminary step. The incomplete isolation of kerogen may introduce some errors and uncertainties in kerogen content estimation. The alteration of kerogen microstructure during this process has also been documented. The current approach still requires input from geochemical measurement of total organic carbon (TOC) while the conversion of TOC to kerogen volume requires the precise value of a conversion factor and kerogen density. Overall, there is yet a standard lab or field scale approach to characterize kerogen content. These difficulties and uncertainties prompt the motivation to attempt a new methodology to quantify the kerogen content of unconventional shale from porosity measurements.
Porosity is the basic rock property that is related to the volumetric average of pore space. The distinction between the total and effective porosity is meaningless for shale and this characteristic property has enabled the preservation of its organic content. The recent popularity and growth of different measurement techniques is in part closely tied to the near zero porosity of shale. Two special cases of practical interest are NMR and density porosity measurements which can both be measured in the rock physics lab and well logs. NMR porosity is sensitive to 1H which is naturally enriched in kerogen whereas density porosity must be calibrated to the mineral matrix.
Based on porosity measurements, the emerging aproach is that the kerogen volume fraction is the contrast between NMR and density porosity. Although, the theoretical basis of this approach is not satisfactory, it is straightforward and far less complicated than the existing approaches to quantify kerogen content. We investigate this concept further based on laboratory measurement. We conducted laboratory measurements of NMR porosity, bulk density, grain density and TOC on Qusaiba shale to characterize its kerogen content. In our approach, we conducted the NMR experiment on the shale samples in the dry state without fluid saturation.
The Cliff Head is one of the most significant discoveries in the offshore Northern Perth Basin. Hence, understanding the structure and geology of the field is essential to further evaluate the offshore region in the basin. Two structural models were developed with the objective to achieve a better understanding of this field. The first model is focused on the Permian and older strata, while the second model is for the overburden. In addition, reservoir properties models (e.g. porosity model and water saturation model) were developed to better understand the reservoir facies and hydrocarbon distribution. Examination of the structural models has shown that there are two main sets of faults within the Cliff Head area, which can be categorized into the following: the deep Permian faults that are truncated against the Late Permian unconformity, and younger Cretaceous faults that were developed during the Early Cretaceous rifting. It has also shown that the oil accumulation within the field is structurally trapped within Permian aged set of horsts and is mainly reservoired within the Irwin River Coal Measures. The secondary target (e.g. the underlying High Cliff Sandstone) is mostly beneath the regional oil-water contact of −1257.8 m TVDss, except in the highest structural point in the field, where Cliff Head-6 was drilled. The Irwin River Coal Measures in the study area contained four high resolution depositional sequences that displayed a finingupward pattern as depicted by the Gamma Ray log response and are interpreted to have mainly deposited in a fluvial depositional system. The High Cliff Sandstone, in contrast, contained two high resolution depositional sequences that displayed a coarsening upward sequences as supported by Gamma Ray log response and were interpreted to have mainly deposited in marginal marine settings. Reservoir properties modeling was also conducted utilizing the 3D models, where a 3D porosity model was calculated and shows that the Irwin River Coal Measures, in general, exhibit higher porosity distribution than the underlying High Cliff Sandstone, even though the later has coarser and more laterally extensive sand sheets. This is probably attributed to diagenetic porosity reduction within the High Cliff Sandstone caused by the formation waters. The calculated 3D water saturation model also confirms the presence of a single regional oil-water contact within the field and hence, reservoir heterogeneities and fault seal capacities did not affect the hydrocarbon distribution within the field. Finally, all the calculated models (e.g. lithofacies model, porosity model, and water saturation model) were integrated to estimate the recoverable hydrocarbons in place, where the Cliff Head is estimated to contain a total of 15.2 million barrels.