Exploration in the Middle East can benefit from the creation of sequence stratigraphy-based, scalable, 3D models of the subsurface that are, in effect, a subsurface digital twin that extends from the plate to pore. Stratigraphic and structural organization are integrated into this model to provide a predictive geological framework for analysis of reservoir- and regional-scale geology. This framework enables testing of novel geologic concepts on the Arabian Plate.
The first step of model design is to temporally constrain data within a sequence stratigraphic framework. Publically available data were used in the entire construction of this model. This framework enables the generation of plate-wide chronostratigraphic charts and gross depositional environment (GDE) maps that help to define major changes in the regional geological context. The integration of a geodynamic plate model also provides deeper insight into these spatial and temporal changes in geology. The subsurface model also adopts the principles of Earth systems science to provide insight into the nature of paleoclimate and its potential effect on enhancing the predictive capabilities of the subsurface model. A set of plate-scale regional depth frameworks can be constructed. These, when integrated with GDE maps and other stratigraphic data, facilitate basin screening and play risking.
This plate to play methodology has yielded value through the development of new play concepts and ideas across the Arabian Plate. Exploration has historically relied on the identification of large structures. However, the majority of these are now being exploited. Underexplored stratigraphic traps, and unconventional resources are new concepts that can be better evaluated by using a digital twin of the subsurface. The integration of seismic data and sequence-stratigraphy-calibrated wireline log data can be used to identify the subcrop pattern beneath an unconformity, as well as regions where potential reservoir rocks are in juxtaposition with seals. Intrashelf basins are a key feature of the Arabian Plate. They lead to stratigraphic complexity, yet are key factors for both source rock and reservoir development. From an unconventional perspective, novel, tight plays that exist within or above prominent source rock intervals can also be established.
Value and insight into previously underexplored play concepts, such as within the Silurian Qusaiba Member and the Cretaceous Shilaif Formation of Abu Dhabi, can thus be generated from the stratigraphic attribution of geoscience data. This data can enable better-informed predictions into "white space" away from data control.
Carbonate reservoir rocks of the Najmah formation in Kuwait, with low porosity and low permeability, have been characterized using integrated digital and physical rock analyses methods. High-resolution imaging and analyses determined the microstructural characters of mineral matrix, organic matter (OM) distribution, organic and inorganic pore types, size distribution, and permeability variation within this kerogen-rich Late Jurassic stratigraphic unit.
Considerable heterogeneity of porosity and permeability was observed in the 100-ft studied interval of the Najmah Formation. Two-dimensional scanning electron microscopy (2D-SEM) imaging and three-dimensional focused ion beam SEM (3D-FIB-SEM) imaging highlighted the different types of porosities present within the formation rock. At each depth, several 2D-SEM images were used for characterization and selection of representative locations for extracting 3D FIB-SEM volumes. The 3D volumes were digitally analyzed and volumetric percentages of OM and total porosity were determined. The porosity was further analyzed and quantified as connected, nonconnected, and associated with organic matter. Connected porosity was used to compute absolute permeability in the horizontal and vertical directions in the area of interest.
Porosity associated with OM is an indicator of OM maturity and flow potential. It has been categorized as pendular type, spongy large grain, spongy small grain, fracture porosity within the OM, grain boundary fractures and intergranular porosity covering the entire OM. Permeability is not only influenced by porosity within OM or even apparent transformation ratio (ATR), it is also dependent on pore connectivity, pore sizes, and heterogeneity (e.g., high-permeability streaks). For high porosity samples, almost all pores are connected and contributing to permeability. For low porosity samples with high permeability, the flow is mainly through microfractures. It is possible that intergranular clay pores in highly thermally mature rocks were originally filled with OM and that, during progressive thermal maturation, transformation of OM to hydrocarbon(s) removed much of the pore filling OM.
It has also been observed that, although the total organic carbon (TOC) content of the rocks is significant (up to 18 wt%), and good maturity index (VR0>1), only few examined samples show good connected porosity within the OM. It is essential to evaluate the porosity within the OM thorough high-resolution measurements for pinpointing the prospective layers for future stimulated horizontal wells in this organic-rich source unit. These intervals can be considered as the potential sweet spots after integration with detailed petrophysics and geomechanical parameters for optimized well planning and completion design.
Kang, Jeonggil (Al Dhafra Petroleum Operation Company) | Eriavbe, Francis (Al Dhafra Petroleum Operation Company) | Girinathan, Sajith (Al Dhafra Petroleum Operation Company) | Mohamed, Alyazia (Al Dhafra Petroleum Operation Company) | Doucette, Neil (Al Dhafra Petroleum Operation Company) | Almehsin, Khalil (Al Dhafra Petroleum Operation Company) | Ali Alloghani, Jasim (Al Dhafra Petroleum Operation Company) | Ali Al-Ali, Abdulla (Al Dhafra Petroleum Operation Company) | Ahmed Al Katheeri, Faaeza (Al Dhafra Petroleum Operation Company) | Bhatt, Pranjal (Baker Hughes, a GE Company) | Franquet, Javier (Baker Hughes, a GE Company) | Zhunussova, Gulzira (Baker Hughes, a GE Company) | Uluyuz, Sila (Baker Hughes, a GE Company)
Several challenges are associated with the characterization of organic rich unconventional plays, most significantly with the identification of sweet spots for optimum placement of horizontal wells, estimation of producible hydrocarbons and subsequent stimulation design. This paper presents the petrophysics and geomechanics integration approach from the X Formation and the important factors for the identification of sweet spots.
The case study concentrates on the X Formation that consists of a succession of argillaceous limestone, mostly fine grained packstones and wackestones together with subordinate calcareous shales in the lower part. The complex carbonate lithology and fabric combined with low porosity and the requirement to evaluate total organic carbon presents a challenge to conventional logs and evaluation of them. Amid all the rock properties, the low permeability and productivity dictate the requirement to stimulate the wells effectively. Detailed integration of advanced and conventional log data, core data, mud logs and geomechanical analysis plays a critical role in the evaluation and development of these organic rich unconventional reservoirs. Extensive data gathering was done with wireline logging suite, which covered Resistivitiy/Density/Neutron/Spectral GR- Acoustic logs – Resistivity & Acoustic Images – Dielectric- NMR - Advanced Elemental Spectroscopy technologies and microfrac tests to characterize the hydrocarbon potential, sweet spots and in-situ stress contrast within the organic rich X Formation. The azimuthal and transverse acoustic anisotropies were obtained from X-dipole data to fully characterize the elastic properties of the formation. The static elastic properties were obtained using empirical core correlations as triaxial core tests were not available at the time of the study. The stress profile was calibrated against straddle packer microfrac tests to identify intervals with stress contrast for proper hydraulic fracturing interval selection.
The integration of conventional and advanced logs enabled the accurate evaluation of total organic carbon (TOC), petrophysical volumes, and sweet spot selection. The advanced elemental spectroscopy data provided the mineralogy, amount of carbon presence in the rock, and consequently the associated organic carbon within the X Formation. The NMR reservoir characterization provided lithology independent total porosity. The difference between the NMR and density porosities provides additional information about organic matter. NMR data was utilized in this case study to identify and differentiate the organic matter and hydrocarbon presence within the X Formation.
Acoustic and image logs provided the geomechanical properties that enable selection of the best intervals for microfrac stress measurement and proper fracture containment modeling. Geomechanical workflow allowed identification of intervals with a good stress contrast in X formation. The core data and stress measurements are recommended for the accurate calibration of the stress profiles and hydraulic fracture propagation modeling.
The extensive data integration work presented in this single-well study within X Fomation, is a key factor for any organic rich unconventional reservoir characterization that integrated geology, petrophysics, mineralogy, and geomechanics for sweet spot identification within tight oil carbonate reservoirs.
Al-Azmi, Mejbel Saad (Kuwait Oil Company) | Al-Otaibi, Fahad (Kuwait Oil Company) | Kumar, Joshi Girija (Kuwait Oil Company) | Tiwary, Devendra (Kuwait Oil Company) | Al-Ashwak, Samar (Kuwait Oil Company) | Dzhaykiev, Bekdaulet (Baker Hughes, a GE Company) | Shinde, Neha (Baker Hughes, a GE Company) | Hardman, Douglas (Baker Hughes, a GE Company) | Noueihed, Rabih (Baker Hughes, a GE Company) | Gadkari, Shreerang (Baker Hughes, a GE Company)
The complex nature of the reservoir dictated comprehensive formation evaluation logging that was typically done on wireline. The high angle designed for maximum reservoir exposure, high temperature, high pressure (HTHP), differential reservoir pressure and wellbore stability challenges necessitated a new approach to overall formation evaluation. The paper outlines Formation Evaluation strategy that reduced risk, increased efficiency and saved money, while ensuring high quality data collection, integration and interpretation.
After review of all risks, a decision to utilize Managed Pressure Drilling (MPD) for wellbore stability, Logging While Drilling (LWD) to replace wireline and Advanced Mudlogging Services was implemented. The Formation Evaluation team utilized LWD resistivity, neutron, density and nuclear magnetic resonance logs supplemented with x-ray diffraction (XRD), x-ray fluorescence (XRF) and advanced mud gas analysis to ensure comprehensive analysis. The paper outlines workflows and procedures necessary to ensure all data from LWD, XRF, XRD and mud gas are integrated properly for the analysis.
Effects of Managed Pressure Drilling on mud gas interpretation as well as cuttings and mud gas depth matching are addressed. Depth matching of all data, mud gasses, cuttings and logs are critical for detailed and accurate analysis and techniques are discussed that ensure consistent results. Complex mineralogy due to digenesis and effect of LWD logs are evident and only reconciled by detailed XRF and XRD data. The effects of some conductive mineralogy are so dramatic as to infer tool function compromise. The ability to determine acceptable tool response from tool failures eliminates unnecessary trips and leads to efficient operations. The final result of the above data collection, QC and processing resulted in a comprehensive formation evaluation interpretation of high confidence.
Finally, conclusions and recommendations are summarized to provide guidelines in Formation Evaluation in similar challenging highly deviated, HTHP, complex reservoir environments on land and offshore.
This seminar will teach participants how to identify, evaluate, and quantify risk and uncertainty in everyday oil and gas economic situations. It reviews the development of pragmatic tools, methods, and understandings for professionals that are applicable to companies of all sizes. The seminar also briefly reviews statistics, the relationship between risk and return, and hedging and future markets. Strategic thinking and planning are key elements in an organisation’s journey to maximise value to shareholders, customers, and employees. Through this workshop, attendees will go through the different processes involved in strategic planning including the elements of organisational SWOT, business scenario and options development, elaboration of strategic options and communication to stakeholders.
Decisions in E&P ventures are affected by Bias, Blindness, and Illusions (BBI) which permeate our analyses, interpretations and decisions. This one-day course examines the influence of these cognitive pitfalls and presents techniques that can be used to mitigate their impact. Bias refers to errors in thinking whereby interpretations and judgments are drawn in an illogical fashion. Blindness is the condition where we fail to see an unexpected event in plain sight. Illusions refer to misleading beliefs based on a false impression of reality.
Amer, AimenAi (Schlumberger) | Sajer, Abdulazziz (Kuwait Oil Company) | Al-Adwani, Talal (Kuwait Oil Company) | Salem, Hanan (Kuwait Oil Company) | Abu-Taleb, Reyad (Kuwait Oil Company) | Abu-Guneej, Ali (Kuwait Oil Company) | Yateem, Ali (Kuwait Oil Company) | Chilumuri, Vishnu (Kuwait Oil Company) | Goyal, Palkesh (Schlumberger) | Devkar, Sambhaji (Schlumberger)
Producing unconventional reservoirs characterized by low porosities and permeabilities during early stages of exploration and field appraisal can be challenging, especially in high temperature and high pressure (HPHT) downhole conditions. In such reservoirs, the natural fracture network can play a significant role in flowing hydrocarbons, increasing the importance of encountering such network by the boreholes.
Consequently, the challenge would be to plan wells through these corridors, which is not always easy. To add to the challenge, well design restrictions dictate, the drilling of only vertical and in minor cases deviated wells. This can reduce the possibility of drilling through sub-vertical fracture sets significantly, and once seismic resolution is considered, it may seem that all odds are agents encountering a fracture network.
This article addresses a case where a vertical well is drilled, in the above-mentioned reservoir setting, and missed the natural fracture system. The correct mitigation can make a difference between plugging and abandoning the well or putting it on production.
The technique utilized is based on a borehole acoustic reflection survey (BARS) acquired over a vertical well to give a detailed insight on the fracture network 120 ft away from the borehole. Integrating this technique with core and high-resolution borehole image logs rendered an excellent match, increasing the confidence level in the acoustically predicted fracture corridors.
Based on these findings new perforation intervals and hydraulic stimulation are proposed to optimize well performance. Such application can reverse the well decommissioning process, opening new opportunities for the rejuvenation of older wells.
Dashti, Jalal (Kuwait Oil Company) | Al-Awadi, Mashari (Kuwait Oil Company) | Mushnuri, Sudhakar (Kuwait Oil Company) | Al-Meshilah, Thuwaini (Kuwait Oil Company) | Shoeibi, Ahmad (Geolog International) | Cecconi, Bianca (Geolog International) | Estarabadi, Javad (Geolog International)
Carbon isotopic characterization of mud gas can add great value to the information collected at wellsite and nowadays the interest in this topic is increasing as documented by the study from Poirier et al. (IMOG 2017).
The presented study has the objective of illustrating the data logged through a cavity ring-down spectroscopic (CRDS) technique that allowed collection of robust and reliable carbon isotopic data at wellsite. The logged carbon isotopic data were then used for studying the behavior of two formations (Makhul and Najmah) across different fields. Makhul Formation represents the lower most Formation of Cretaceous in Kuwait, representing predominantly as carbonate rock. In lower Makhul, the high gamma radioactivity is due to enrichment of the shales by uranium. While, Najmah formation is an excellent source rock located in upper Jurassic, it consists of black calcareous limestone source rock with high organic content. Both formations are considered as major source rocks for petroleum systems in state of Kuwait. Many standard interpretation models from the literature were screened and adopted in inter-field correlation, resulting in a good matching with the geographical distribution of the fields.
The second part of the study will focus on the added value of recording carbon isotopic ratios up to C3. The analysis of δ13C3 is demanding from the instrumental point of view, thus, the benefits in terms of formation evaluation that comes from the logging of isotopes up to C3 will be illustrated in the study. With reference to other literatures, δ13C1 readings might be affected by mixing phenomena with biogenic gases, and thus they are not the best candidates to run maturity assessment through isotopes. Instead, carbon isotopic ratios of ethane and propane are not affected by mixing with biogenic gas, resulting in more robust and accurate interpretations. Few models from literature were applied on collected data, allowing choosing the one that matches best the behavior of the studied basin.
Independent measurements on the maturity of the source rock in the area confirmed that the trend highlighted through carbon isotopes logging at wellsite is correct, validating the usefulness of this technique at wellsite.
Bhatt, Pranjal (Baker Hughes, a GE company) | Zhunussova, Gulzira (Baker Hughes, a GE company) | Uluyuz, Sila (Baker Hughes, a GE company) | Baig, Muhammad (ADNOC) | Makarychev, Gennady (ADNOC) | Mendez, Alfredo (ADNOC) | Povstyanova, Magdalena (ADNOC)
Several challenges are associated with reservoir characterization of organic-rich, unconventional plays, most significantly with estimating producible hydrocarbons and identifying sweet spots for horizontal wells and subsequent stimulation. This paper illustrates the data integration approach from the Shilaif member and the important factors for the hydraulic fracturing simulations and execution.
The Shilaif member consists of a succession of argillaceous limestone, mostly fine-grained packstones and wackestones with subordinate calcareous shales in the lower part. The complex carbonate lithology and fabric, combined with low porosity and the requirement to evaluate total organic carbon, presents a challenge to conventional logs and evaluation. Low permeability and productivity dictate the requirement to stimulate the wells effectively. Thorough integration of advanced and conventional log data (resistivity, neutron/density, dielectric, advanced acoustic, spectroscopy, nuclear magnetic resonance (NMR), and images) with core data and mud logs plays a critical role in the evaluation and development of these organic-rich reservoirs.
Extensive data acquisition was planned with a wireline suite that included resistivity/density/neutron/spectral gamma ray; acoustic logs; acoustic image; NMR; advanced elemental spectroscopy; and dielectric technologies to characterize the hydrocarbon potential of organic-rich rock within the Shilaif member. The same suite of logs are critical for hydraulic fracturing simulations and play a heavy role when executing and pressure-matching the fracture geometry.
Lithology and porosity from neutron/density logs are refined with NMR and spectroscopy to enable accurate evaluation of total organic carbon (TOC) and volumes. The advanced elemental spectroscopy data provided the mineralogy, the amount of carbon in the rock, and consequently the associated organic carbon within the Shilaif member. The NMR technology provided lithology-independent total porosity. The difference between the NMR and the density techniques provides accurate information about organic matter. NMR technology in this present case study was used to identify and differentiate the organic matter and hydrocarbon presence within the Shilaif member. Acoustic and image logs were used to evaluate the geomechanical properties that enable stimulation design to maximize the drainage while remaining within the boundaries of the reservoir. Accurate calibration of the stress profiles from core data assured the stimulation design was operationally achievable within pressure specifications and bounding formations. Detailed knowledge of natural fracture networks was critical to building an accurate geomechanical model.
A complete workflow from formation evaluation to selection of interval to stimulate the Shilaif formation will be presented and used for future well development.
The data integration work illustrated in the paper is a key for unconventional reservoir characterization that enabled identification of the sweet spots for horizontal wells and the successful hydraulic fracturing in the organic rich rocks of the Shilaif member.
A significant fraction of the world gas needs is supplied from gas-condensate reservoirs. The well productivity of these reservoirs is compromised because of liquid condensation in the matrix and fracture. The Sabriyah field is the first successful exploration in the North of Kuwait which led to the discovery of six extensive, deep, tight gas-condensate reservoirs. A purely fracture-dominated unconventional resource play, Najmah-Sarelu formation, is considered the source for most of the reservoirs in the Sabriyah field. In this paper, a compositional, multi-phase, dual-porosity model was used to analyze an existing horizontal well performance, and to evaluate potential enhancements to the future production.
The Sabriyah gas-condensate field in North of Kuwait is an abnormally high-pressure tight reservoir, which has very low matrix permeability and porosity. In this study, the geological system of Sabriyah field was studied using a static model to decipher the complexity of the reservoir—especially, the Najmah-Sarelu formation. A well's performance was analyzed using history-matching of the production data using a multi-component compositional dual-porosity model. To assess potential enhancement of the future production, eight different scenarios were studied. Specifically, we extended the current horizontal well length and added several multi-stage hydraulic fractures to increase production.
To assess the flow behavior of gas-condensate in Sabriyah field, we began with a study that tied the reservoir geology to the performance of a typical well using both static and dynamic simulation models. Both pressure build up and production data were analyzed using pressure and rate transient techniques which yielded an effective formation permeability of 0.5 to 0.6 mD. The numerical modeling parameters achieved a successful history match for one year of production, and the sensitivity analysis demonstrated that producing at a pressure of slightly below the dew point yielded the largest amount of condensate production. In particular, the additional condensate production was twenty-two percent for this case. Also, we observed that the existing horizontal well performed as effectively as having three-stage hydraulically fractured well in a matrix-dominated situation because of the presence of existing natural fractures replace the effect of the multi-stage fracturing.