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A key component of an unconventional reservoir development is 3D characterization. A necessary precursor for any seismic inversion work is an inversion feasibility study. We shall demonstrate a best practice inversion feasibility workflow that has several key components: regional geology, petrophysics, rock physics, and geophysical analysis. The study shows an integrated approach using spatially diverse well data to cover the entire Delaware Basin, focusing on Avalon and Bone Springs formations. The results show the ranking of petrophysical properties that contributes to the changes in elastic properties. A good relationship was established between TOC, vclay and porosity to elastic logs using both conventional and unconventional RPMs. A class-IV AVO response was observed in the Avalon formation. Finally, our analysis showed that a depth trend based 1D Bayesian classification using bandlimited log data was able to separate organic rich high TOC facies from siltstones and carbonates. To conclude, an integrated approach involving geology, petrophysics, rock physics and inversion feasibility study increased our understanding of the basin and set path for further analysis. The results from inversion feasibility can be used to understand what facies and how much resolution can be resolved from an inversion which is further used to guide the drilling direction and landing zones. The workflow outlined in this study potentially can lead to a 3D inversion analysis, reservoir property estimations from seismic, TOC mapping and finally for finding sweet spots and better drilling/landing zones in the subsurface.
Unconventional oil and gas production have increased dramatically in the last decade, and in the U.S., the Permian Basin is the most prolific of all the basins. The Delaware Basin located in the western part of the Permian Basin has become one of the most active drilling sites with multi-stacked plays (Mire et al. 2017). Most of the production comes from the Permian-aged Avalon, Bone Springs and Wolfcamp formations. These formations are comprised of a heterogeneous mixture of organic rich mudrocks, siltstones and carbonates (Nester et al., 2014). Due to the complex nature of these rocks, it is advantageous to understand and extract useful information from available data resources from all disciplines. Hence, a collaboration to perform an integrated approach between different disciplines is crucial to effectively find solution for complicated technical challenges in the Delaware Basin (Hoang et al., 2019; Anantharamu and Del Moro, 2019).
The knowledge of geology and petrophysical analysis enhances our understanding of the basin and its mineral constituents. A proper rock physics analysis is extremely important for establishing a link between elastic properties and reservoir parameters, which can later be extrapolated to 3D domain using seismic and inversion workflows.
Lv, Zuobin (CNOOC China Limited, Tianjin Branch) | Song, Hongliang (CNOOC China Limited, Tianjin Branch) | Wang, Pengfei (CNOOC China Limited, Tianjin Branch) | Fang, Na (CNOOC China Limited, Tianjin Branch) | Zheng, Bin (CNOOC China Limited, Tianjin Branch)
The resolution of seismic data in the semideep reservoirs ranging from 1500m to 3000m is low, and reservoir prediction is difficult when well data are scarce (
In order to solve this problem, this paper proposes a well-seismic integrated reservoir prediction technique based on seismic data frequency division processing and lithofacies distribution prediction technique based on sedimentary numerical simulation. On the basis of reservoir prediction, 3D reservoir geological modeling is carried out. With the reservoir prediction results as the constraint conditions, the sedimentary microfacies modeling is firstly developed, and then reservoir petrophysical modeling is carried out under microfacies constraints. The fine geological modeling of complex semideep reservoir is realized. Compared with the traditional geological model based on the constraint of 2D sedimentary microfacies map, the new modeling method has higher accuracy. The geological model established by the new method can more accurately predict the spatial distribution, porosity and permeability properties of reservoirs.
However, other technologies can often be employed to investigate properties of the earth that correlate better with the properties of interest. If the images from these technologies can be provided at appropriate resolution, and if the knowledge required for interpretation and wise application of these technologies is available within the industry, they should be used. For example, electrical methods are extremely sensitive to variations in saturation, yet surface-based methods provide very poor resolution. Reservoir compaction can be directly observed from surface deformation, and pore-volume or gas-saturation changes can be detected from changes in the gravitational field. Dramatic examples of surface deformation induced by reservoir compaction have been provided by releveling studies (involving repeated high-accuracy surveying) and satellite-based interferometry.
There are different definitions of what is Well Integrity. The most widely accepted definition is given by NORSOK D-010: "Application of technical, operational and organizational solutions to reduce risk of uncontrolled release of formation fluids throughout the life cycle of a well." Other accepted definition is given by ISO TS 16530-2 "Containment and the prevention of the escape of fluids (i.e. Well Integrity is a multidisciplinary approach. Therefore, well integrity engineers need to interact constantly with different disciplines to assess the status of well barriers and well barrier envelopes at all times.
The Ekofisk oil field is in the North Sea, south of Norway, with an estimated 6.4 billion bbl stock tank original oil in place (STOOIP). It is a large, carbonate reservoir that has two zones, Ekofisk and Tor, that are high-porosity, fractured chalks with matrix permeabilities of approximately 1 md and effective permeabilities that range from 1 to 50 md. Discovered in 1969, the Ekofisk field was found at very high pressure [7,120 psia at 10,400 ft true vertical depth subsea (TVDSS)] but with an initial bubblepoint pressure that was 1,600 psi below initial reservoir pressure. Ekofisk's oil is 38 API, has a viscosity of approximately 0.25 cp, and has a solution gas/oil ratio (GOR) of more than 1,500 scf/STB. Primary production began in June 1971 and peaked in 1976 at 350,000 barrels of oil per day (BOPD) from 30 production wells (with 8 gas reinjection wells).
The Long Beach Unit (LBU) area of the Wilmington oil field (southern California, US) is mainly under the Long Beach harbor and contains more than 3 billion bbl of original oil in place (OOIP). This oil field is a large anticline that is crosscut by several faults with displacements of 50 to 450 ft. It consists of seven zones between 2,500 and 7,000 ft true vertical depth subsea (TVDSS), the upper six of which are turbidite deposits of unconsolidated to poorly consolidated sandstone (1 to 1,000 md and 20 to 30% BV porosity) interbedded with shales. The gross thickness of 3,300 ft contains 900 ft of sandstone. From its discovery in 1936 to the 1950s, most of the onshore portion of this oil field (the non-LBU area of the Wilmington oil field) was produced using the pressure-depletion oil-recovery mechanism.
Van Dijk, Janpieter (Dragon Oil) | Ajayi, Ayodeji Temitope (Dragon Oil) | De Vincenzi, Luca (Dragon Oil) | Ellen, Helby (Dragon Oil) | Guney, Hasan (Dragon Oil) | Holloway, Philip (Dragon Oil) | Khdhaouria, Mourad (Dragon Oil) | Mcleod, Ian Stewart (Dragon Oil)
The Gulf of Suez Basin (GOS), a World Class Hydrocarbon Province, is a typical Continental Rift, but many perplexities arise from the different proposed evolutionary models.
Previous models described extension along (N)NW-(S)SE faults generating antithetic half grabens, but these models show numerous difficulties and are not able to capture all observed elements into one single frame, as the reconstructions are hampered by low seismic resolution below the heterogeneous Upper Miocene salt. Our analyses (from outcrop, seismic, well logs, gravimetry, magnetometry, dipmeter, and seismic and magnetic reprocessing), performed over the last years, allows the definition of a new tectonic model better describing these features: The GOS evolution is placed in a sinistral transtensional regime, reinterpreting the Duwi (WNW-ESE), Clysmic (NW-SE), Aqaba (NNE-SSW), and Cross (NE-SW) trends and the two (twist) accommodation zones, showing two distinct episodes resulting in overprinting of differently trending and tilting fault blocks. Furthermore, it tackles perplexities related to the link between subsidence amounts/rates (backstripping), and extension, strain distribution, and episodes/pulses/unconformities. It describes the increase in extension towards the south in the rift-sphenochasm and resolves the enigmatic relationship between high angle faults (that dominate the area), low angle dipping older faults and rotated pre-rift successions.
Our model foresees a two staged evolution: Initial rifting (Early Miocene - E1; Abu Zenima, Nukhul, Rudeis series) occurred along WNW-ESE trending (Duwi) faults disposed in an en-echelon manner as a result of a sinistral transtension. These faults progressively rotated in some areas towards a low angle with accompanied high angle "antithetic" tilted pre-rift strata. Subsidence accelerated during the Early Miocene, and some of these tilted fault blocks show erosion surfaces partly related to the final Early Miocene tectonic pulse. In a second stage (Mio- Pliocene - E2; Kareem, Belayim series, South Garib salt, Zeit evaporates) this pattern is overprinted by a new set of high angle rift faults trending (N)NW-(S)SE (Clysmic) cross-cutting the previous faults, but without any major block rotation. The Late Pliocene-Pleistocene (E3; Post Zeit, Shulher series) large (accelerating) differential uplift and subsidence, shows "synthetic tilting" of the strata along the rift margins, local tectonic inversions in different episodes, syn- sedimentary detachment along the mobile salt layer with the generation of en-echelon ridges, generating the present day complex fault pattern (sigmoidal intervening trends and cross trends), and differently tilted smaller fault blocks. The new model is fully compatible with the pulsating NNE-NE movement of the Sinai Plate, associated with the NE moving Arabian Plate and Red Sea rifting, and has severe consequences for further Exploration and Development in the GOS, as it describes the configuration of the Hydrocarbon Fields in a more comprehensive way and predicts the occurrences of undiscovered Prospects.
Grujic, B. (University of Banja Luka) | Shimizu, N. (Yamaguchi University) | Sudi Parwata, I. Nyoman (Yamaguchi University) | Grujic, Z. (University of Banja Luka) | Zekan, S (University of Tuzla) | Vrkljan, I. (University of Rijeka)
This paper describes the key elements of development numerical model and performing elasto-plastic and visco-plastic 3D analysis, which has not previously been developed in relation to the problem of the Tuzla Salt Mine in Bosnia and herzegovina or similar salt mines problems. Nonlinear finite element analysis allow the calculation of stresses and deformations, and so obtain the data needed to assess the stability of the salt caverns over time, and thereby the surface subsidence across the extensive area of the city of Tuzla. This required the introduction of upgrade simulation software packages ABAQUS for solving the complex problem of the Tuzla Salt Mine. It is another new and important factor in the development of numerical model, because the finite element method and computer simulation are powerful tools that assist the management and engineering force of mining companies with taking reasonable decisions about and steps toward improving the quality of work and safety of all employees, as well as the whole environment in the zone of subsidence. Results of stress strain analysis have been compared with measured values (vertical displacement of surface), over a period of time.
The Tuzla Salt Mine is considered as a major and one of the most serious ground displacement problems in B&H, and also in Europe. Uncontrolled salt extraction from this mine has produced about 80,000,000 m3 of salt water, with a salt mass deficit of about 12,000,000 m3 created below the immediate urban area of the city of Tuzla. This long-term uncontrolled process of extraction of salt water from the Tuzla mine has resulted in ground subsidence in the central part of the city, causing significant damage to the city infrastructure and facilities. Ground subsidence and surface deformation have caused the demolition of about 2,700 housing units, approximately 67,000m2 of production facilities, and 130,888m2 of educational, health, cultural, and sports facilities. Due to this, 15000 inhabitants have been displaced from the affected area. The catastrophic consequences arising on the ground surface necessitated the closure of the salt mine and salt caverns is filled with water. Although salt water leaks have been detected and sealed, ground across the city of Tuzla has continued to subside, with the occurrence of landslides, unstable slopes, and other types of ground movement.
One of the PDO’s largest producing field with vertically stacked carbonate reservoirs gas from shallower Natih Formation, and produces oil from lower Shuaiba formation with waterflood recovery. Natih formation is a highly compacting formation characterized using rock mechanics laboratory measurements. Currently there are more than 500 Shuiaba wells that are active, which penetrate through the highly compacting Natih Layer above. Reservoir compaction of Natih A has induced damage to several wells most likely due to compression and buckling of the casing within the production interval. The field has obeservations to well integrity and impact to production performation related to the casing deformation resulting from the compaction.
The well Integrity issues for Shuaiba wells are being resolved with work over operations, repairs. In few severe cases, it was required to abandon the well. All of these issues impact operational expenditure and production (loss and/or deferment). Risk assessment for wells with future depletion (or time) can provide input to manage the risk, plan adequate mitigations and capture the impact in the future drilling campaigns for well stock. To do so it was important to identify and quantify well counts, which have high potential to have well integrity issues or risk of failure
In the studied field, subsurface compaction is being monitored/measured since 2000, using Compaction Monitoring Instrument (CMI) that measures compaction between preplaced radioactive markers in the formation and the casing in five CMI monitoring wells. Data of CMI compaction log, historical well failures, spatial well locations, rock mechanics measurements was integrated to quantify risk of expected well failures in future. The results from the CMI logging showed that the compation in the entire reservoir interval is not uniform and upper layers in the reservoir intervals were subjected to very high compaction strains compared to lower layers. The Uniaxial Pore Volume Compressibility (UPVC)) coupled with analysis of CMI data provides a forecast for maximum compaction strain in the upper reservoir layers up to 5 % at abandonment pressure.
The analysis of reported/observed well failures reveals that approximately 77% of the impacted wells were during 1971-2000. Using these inputs a risk assessment matrix for well failures was developed, which provided potential wells with high risk of failure/well integrity issues, which accounted to about 34% (~ 85 wells) of the active wells. Results of this study provided input to capture in the development plans and build adequate mitigations to help minimize production loss/deferment
Sajjad, Farasdaq (PT Pertamina Hulu Energi Offshore Northwest Java) | Chandra, Steven (Institut Teknologi Bandung) | Naja, Savinatun (PT Pertamina Hulu Energi Offshore Northwest Java) | Suganda, Wingky (PT Pertamina Hulu Energi Offshore Northwest Java)
We present a simple analytical solution to diagnose gas production under compaction. This solution scales production profile of different wells and collapses them into a single general curve. The curve will later serve as the "learning" function for physic-based machine-learning prediction.
A rapid growing flood of big data in the oil and gas industry reveals a substantial opportunity to the better understanding of hydrocarbon reservoir. With machine learning, one can turn a numerous amount of data to predict future production and determine field economics. However, the quality of the prediction from machine learning is dependent on the learning function selected that most of the time does not concatenate any physical aspects of the problem. In this paper, we offer a better machine learning with a physics-based function to estimate future gas production under severe compaction.
We construct a physic-based master curve by solving the coupled Darcy-Biot equation for vertical gas well under reservoir compaction. We assume that the flow is radial and the porosity is transiently changing by the reduction in pore pressure due to gas production. Finally, we reduce the complexity of the coupled non-linear equation to two scaling optimization parameters: a mass scaling factor to scale the recovery factor and time scaling factor to scale the diffusion time.
We verify our model with a field case from KLX field, Indonesia. This gas field produces an enormous amount of gas with subsidence as the side effect. The subsidence was identified by knowing the change in platforms level. By collapsing the production profile of all existing wells into a single master curve, we capture the universal scaling parameters that represent the behavior of gas flow under reservoir compaction. Furthermore, we can substitute the resulted master curve as the learning function for to the machine-learning model to predict and diagnose other fields in the future that undergo the same phenomena.
We find that reservoir compaction leads to a higher recovery factor of gas for a long term. However, the high subsidence rate is not a favorable condition for the offshore field as the production facilities on the platform will submerge under sea level in a matter of years. Thus, the field owners must consider some subsidence mitigations such as injection and maintaining critical production rate.
Our novelty is to produce a general scaling to describe gas production under compaction, which is later useful for the development of our machine-learning process to simplify the prediction process, not involving extensive and expensive numerical simulation.