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Sajer, Abdulaziz (Kuwait Oil Company) | Al-Bader, Haifa (Kuwait Oil Company) | Al-Rabah, Abdullah (Kuwait Oil Company) | Singh, Sunil (Kuwait Oil Company) | Harami, Khalid (Schlumberger) | Dillabough, Garahm (Kuwait Oil Company) | Al-Ajmi, Afrah (Kuwait Oil Company) | Al-Ibrahim, Abdullah (Kuwait Oil Company) | Ayyavoo, Mani Maran (Kuwait Oil Company) | Al-Ateeq, Abdullah (Kuwait Oil Company) | BoSalhah, Ammar (Kuwait Oil Company) | Dashti, Jalal (Kuwait Oil Company) | Al-Qattan, Faisal (Kuwait Oil Company) | Al-Houti, Shoroq (Kuwait Oil Company) | Mushnuri, Sudhakar (Kuwait Oil Company) | William, Awad (Schlumberger) | Arguello, Luis (Schlumberger) | Sangani, Pratik (Schlumberger) | Chakravorty, Sandeep (Schlumberger) | Franco, Francy (Schlumberger) | Sahmkow, Roberto (Schlumberger)
Conventionally discovery to development of a heavy oil reservoir takes very long (Minimum 10-15years). However, significant volatility in the oil prices have required more collaborative workflows and strategies from operators and service companies to optimize cost and maximize efficiency and innovation. We present here a joint service integrated model between an NOC and a service company which was used in the fast track development of an unconventional heavy oil reservoir and resulted in discovery to production in record time.
A conceptual field development plan was put in place for fast track development of the Lower Fars reservoir in the Umm Niqqa field after drilling and testing 26 exploration wells. The plan consisted of drilling and completing over 80 wells in conjunction with the construction and commissioning of an early production facility (EPF) to handle the sour heavy crude. Given the brief time and the unconventional nature of the reservoir, significant challenges were faced during the execution phase. To address the challenges, an integrated workflow was put in place combining multiple disciplines. The entire project required seamless integration between drilling, characterization, production and surface facility teams for flawless execution. The collaboration resulted in successfully drilling and completing all planned wells in less than 1 year.
This paper describes the tasks performed during the project for successful execution. It was initiated by a robust assessment of the discovery in terms of OIIP and type of hydrocarbon. It further describes the construction of a fit for purpose field development plan. During the execution phase we explain the challenges faced while drilling deviated wells in soft unconsolidated reservoirs with extremely shallow kick off points. The challenges in logging and evaluating deviated wells to optimize completion strategy are also described. The optimization of testing, completions and artificial lift workflows played a significant role is assessing the dynamic behavior of these reservoirs. The workflows in conjunction with continuous production monitoring and workover planning allowed the minimization of non-productive time (NPT). We further highlight the surface facility designed for such heavy sour crude and the recommendation for future development.
Al-Ajmi, Saad A. (Kuwait Oil Company) | Pattnaik, Chinmaya (Kuwait Oil Company) | Al-Dawood, Ahmed E. (Kuwait Oil Company) | Dashti, Qasem (Kuwait Oil Company) | AlFailakawi, Abdul Aziz H. (Kuwait Oil Company) | Chakravorty, Sandeep (Schlumberger Oilfield Eastern Limited) | Chandan, J. Keot (Schlumberger Oilfield Eastern Limited) | El-Derini, Khaled M. (Schlumberger Oilfield Eastern Limited)
Kuwait Oil Company is currently engaged in an early phase development of deep sub-salt tight naturally fractured carbonate reservoirs. These reservoirs has been tested and found to be gas bearing. They are uniquely characterized by dual porosity nature where natural fracture network systems are the primary flowing mechanism. The foremost challenge to produce from these reservoirs is the wellbore interaction with the natural fracture network systems. Despite drilling around 85 vertical and slightly deviated wells in this large challenging HP/HT reservoir complex, understanding and characterization of fractures is a challenge in the absence of horizontal wells, though fracture understanding has improved over time through careful integration and interpretation of logs, core, and seismic data. To achieve the dual objective of characterizing the fractures and to boost production, asset team recently embarked on the strategy to drill horizontal wells targeting these challenging tight reservoirs. As a fit for purpose solution to address these challenges, "High Definition Deep Directional Multi Boundary Detecting Technology" was incorporated in the drilling plan so that horizontal producers could be geosteered in the desired target intersecting as much fractures as possible. This technology, an advancement on the 1st generation "Distance to Boundary" technology is characterized by its extended capability to detect multiple bed boundaries based on resistivity contrast up to 20ft around the wellbore. The significantly improved new multilayer stochastic inversion also solves for structural dip along the wellbore azimuth (longitudinal dip). In the lateral section, this technology successfully mapped the reservoir roof as well as multiple thin intra layers inside the target reservoir along with information on longitudinal dips which helped immensely to optimize trajectory inclination and spatially position the wellbore across different layers as per plan. Apart from detecting reservoir boundaries, the inversion also mapped conductive and resistive fractures cutting wellbore at high angle for the first time, while trajectory was drilling across a fracture corridor. This further added confidence to geo-steering while drilling as wellbore cutting through such a fracture corridor was highly anticipated in predrill planning. Drillpipe conveyed borehole images acquired after drilling the well confirmed the presence of large swarms of fractures detected through inversion.
The effective integration of data from different fields in a single platform, like LWD logs, boundary information, dip information, drill cuttings information and decisions taken based on the interpreted information paved the way for the successful drilling of this well and achieve the predrill objectives.
Rao, Jonna Dayakar ((Kuwait Oil Company)) | Al-Ashwak, Samar ((Kuwait Oil Company)) | Al-Anzi, Abdullah Motar ((Kuwait Oil Company)) | Maki, Musaed Yaseen ((Kuwait Oil Company)) | Narhari, Srinivasa Rao ((Kuwait Oil Company)) | Dashti, Qasem ((Kuwait Oil Company)) | Chakravorty, Sandeep ((Schlumberger))
Organic-rich Kerogen of Lower Kimmeridgian to Upper Oxfordian age comprises of thinly laminated Kerogen with calcareous mudstone deposited in deep basinal environment. It has a consistent thickness of 50' in the entire study area with an average porosity of 4-6pu with nanodarcy permeability and is the main source for hydrocarbon plays in Kuwait. This rock sequence occurs at depths of 14000-15000 ft under HPHT conditions. Huge success of shale gas plays in North America has prompted the characterization of these source rocks to evaluate their resource play potential for the first time in Kuwait.
The Kerogen under study differs from proven US Shale gas fields in terms of comparatively higher TOC content, greater depth and much less in thickness (50ft) and in a Pre-salt setting. Hence these are challenging in terms of completion and production. These are inferred to be Type II Oil & Gas prone based on Vitrinite reflectance range from 0.98 to 1.17.
Tight rock analysis (TRA) and geo-mechanical studies of selected core samples within the study area provide critical input for Kerogen characterization. Kerogen is divisible into seven units based on electro-logs and log derived TOC and are correlatable with distinct facies assemblage, TRA derived petrophysical data and Geomechanical properties. Core derived UCS, Triaxial Compression test and Brazilian test based on lab results have brought out clear anisotropic behavior and enabled to bring out mechanical stratigraphy by integrating geomechanical properties and litho-facies variations within the Kerogen. This workflow has brought out the distinction of the carrier beds in alternations with Kerogen-rich layers as well as planned well trajectory along the carrier bed in the central part of Kerogen. Lastly, proppant compatibility tests combined with Young's Modulus provide valuable input for planning horizontal wells and subsequent hydro-frac design for completion.
Acharya, Mihira N. (Kuwait Oil Company, Kuwait) | Chakravorty, Sandeep (Schlumberger, Kuwait) | Al-Mershed, Abdul Mohsen (Kuwait Oil Company, Kuwait) | Darous, Christophe (Schlumberger, Kuwait) | Joshi, Girija K. (Kuwait Oil Company, Kuwait) | Al-Ajmi, Mejbel S. (Kuwait Oil Company, Kuwait) | Dashti, Qasem (Kuwait Oil Company, Kuwait)
A comprehensive geomechanical analysis i.e. broader geomechanical framework of the overburden section and a detailed geomechanical characterization at the reservoir targets for drainhole section, for the best possible orientations and stability parameters during drilling and completion is a key for the fields with sparse vertical and deviated wells control and short production history. This paper outlines the integrated approach adopted and discusses the challenges and uncertainties in the reservoir geomechanical modelling and characterization. Interpretation of caliper data and borehole images are used to determine the stress direction for vertical and near vertical wells. The minimum stress and maximum stress directions are established from orientation of breakouts, maximum ovality from calipers and from orientation of drilling induced fractures respectively. Comprehensive integrated geomechanical properties for all the formations units of the unconventional reservoir sequence are computed. The results indicate that the stress regime varies from'strike-slip to inverse' and are found being formation dependent with associated intrinsic rock mechanical properties and spatial position of the wells under study.
Joshi, Girija (Kuwait Oil Company) | Acharya, Mihira Narayan (Kuwait Oil Company) | Al-Azmi, Mejbel Saad (Kuwait Oil Company) | Dashti, Qasem M (Kuwait Oil Company) | Van Steene, Marie (Schlumberger Oilfield Eastern Limited) | Chakravorty, Sandeep (Schlumberger Oilfield Eastern Limited) | Darous, Christophe (Schlumberger Oilfield Eastern Limited)
The deep organic-rich calcareous Kerogen of North Kuwait, a continuous 50ft thinly alternating carbonate - organic-rich argillaceous sequence, is not only a source rock but has gained importance as potential reservoirs themselves of typical unconventional category. Kerogen characterization relies on quantifying total organic carbon (TOC) and estimating accurate mineralogy. This paper describes an attempt to directly measure TOC of the Limestone-Kerogen sequence.
For the present study, empirical estimations of TOC have been carried out based on various conventional log measurements and also nuclear magnetic resonance. The introduction of a new neutron-induced capture and inelastic gamma ray spectroscopy tool using a very high-resolution scintillator and a new type of pulsed neutron generator for the deep unconventional kerogen resources have provided a unique opportunity to measure a stand-alone quantitative TOC value using a combination of capture and inelastic gamma ray spectra. In this process, Inorganic Carbon Content (ICC) is estimated by using elemental concentrations measured by this logging tool in addition to measuring Total Carbon (TC). The difference between TC and ICC gives direct TOC.
The advanced elemental spectroscopy tool measurements were first used to determine accurately the complex mineralogy of the layered carbonate and organic-rich shale sequence. The petrophysical evaluation and heterogeneity seen on borehole image logs were calibrated with extensive laboratory measurements of core / cuttings data. The final results are considerably improved compared to conventional empirical estimation. Once the mineralogy is properly determined, the log-derived TOC matches very well with core measured TOC.
This technique has provided a new direct and accurate log-derived TOC for Kerogen characterization. The application has a potential to be used for CAPEX optimization of the coring in future wells. This technique can also be applied in HPHT and High-angle horizontal wells, which can overcome challenging coring difficulties in horizontal wells.
Narhari, Srinivasa Rao (Kuwait Oil ) | Al-Ashwak, Samar (Kuwait Oil ) | Kidambi, Vijaya Kumar (Kuwait Oil ) | Al-Ajmi, Neema Hussain (Kuwait Oil) | Neog, Nilotpaul (Kuwait Oil ) | Rao, Jonna Dayakar (Kuwait Oil ) | Al-Dousiri, Musaed Y m (Kuwait Oil ) | Narayan, Acharya Mihira (Kuwait Oil ) | Erkan, Fidan (Kuwait Oil ) | Dashti, Qasem (Kuwait Oil ) | Darous, Christophe (Schlumberger) | Chakravorty, Sandeep (Schlumberger) | Miller, Stephen (Shell)
Organic rich Kerogen layer of Lower Kimmeridgian to Upper Oxforidan age, deposited throughout Kuwait, is a TOC rich layer with varying TOC content between 2 to 20 wt% (in the vertical section) and having an average TOC of about 8 wt%. The depth of occurrence of this layer favorably places this zone to be having potential in rich gas condensate resource in the northern part of Kuwait. This layer occurs at a depth of 14000-16000 ft with a reservoir temperature of 270°-275°F, pressure of 11000 psi and average thickness of over 50ft. This is one of the main source rocks for majority of the oil and gas fields of Kuwait. This Kerogen section is penetrated through a number of vertical wells, as part of development of deeper reservoirs in this area, which offers an excellent opportunity to evaluate this section through core and open hole log data. Because of the strong acoustic contrast with the overlying and underlying layers, this reservoir section is a very strong mappable seismic reflector.
As part of appraising the potential of this layer, as a resource play, a comprehensive success criteria has been worked out for location selection. An integration of all available geo-scientific data such as geochemical, 3D seismic attributes, petrophysical analysis, borehole image interpretations, geo-mechanical, core and mud logs has been carried out. The above data integration/analysis was combined with the success criteria, leading to selection of sweetspots for planning the first dedicated horizontal wells targeted on this layer.
This paper presents the success criteria worked out and the integration of data for high grading the locale - sweetspots, for the first set of horizontal wells for appraising this deep HP-HT unconventional play of Kuwait.
Acharya, Mihira Narayan (Kuwait Oil Company) | Al-Ajmi, Saad A. (Kuwait Oil Company) | Al-Azmi, Mejbel S. (Kuwait Oil Company) | Joshi, Girija K. (Kuwait Oil Company) | Dashti, Qasem M (Kuwait Oil Company) | Al-Anzi, Ealian H D (Kuwait Oil Company) | Chakravorty, Sandeep (Schlumberger Oilfield Eastern Limited) | Darous, Christophe (Schlumberger Oilfield Eastern Limited)
The tight deep carbonate reservoirs of Oxfordian age in North Kuwait consist of tight limestone interbedded with organic rich shale layers. The overall matrix porosity is generally very low and the production is mainly from fractures in the crestal part of main structures. Borehole images are routinely acquired in vertical to moderately deviated wells drilled with oil-base mud for fracture characterization.
For detailed fracture property evaluation, a highly deviated pilot hole was drilled with water-base potassium formate mud for the first time across the reservoir section and drill-pipe conveyed high-resolution electrical borehole image data was acquired. The upper half of the interpreted interval showed potential open fractures sets, NE-SW striking fracture set was most abundant. An advanced fracture segment extraction workflow was used to determine porosity and aperture of different fracture sets.
The first horizontal well was then drilled as a lateral in the target reservoir with oil-base mud restricting direct computation of fracture properties. The electrical and acoustic images in OBM indicated fracture concentrations at quite a few places along the horizontal well trajectory, the most conspicuous occurring at the zones where heavy mud losses were encountered while drilling. A 2D litho-structural model was constructed along the well trajectories using the dip data and open-hole logs to correlate finer carbonate and organic shale layers and fracture distribution across the layers. This workflow permitted extending fracture properties along horizontal well as well.
Finally, a high-resolution 3D structural model was constructed using outputs from previous workflows and data from two nearby vertical / less deviated wells. The final model showed a folded structure, which was absent in the existing model of the field. Thus the innovative workflow provides a means to generate an accurate structural and fracture model for the reservoir, integrating the fracture characteristics of the individual sub-layers with the main fracture corridors.
Alenezi, Abdullah Matar (Kuwait Oil Company) | Narhari, Srinivasa Rao (Kuwait Oil Company) | Alajmi, Neema (Kuwait Oil Company) | Pattnaik, Chinmaya (Kuwait Oil Company) | Rao, Jonna Dayakar (Kuwait Oil Company) | Al-ateeqi, Khalid Abdullatif (Kuwait Oil Company) | Saffelbach, Christian (CORIAS) | Aris, Abdel-Hamid (Corpro Systems Ltd.) | Chakravorty, Sandeep (Schlumberger)
Reliable fracture characterization is essential for efficient field development of tight carbonate reservoirs. A comprehensive campaign of core based fracture analysis was carried out on more than 7,000ft of deep tight carbonate (over 14500ft TVD and 3pu avg. porosity and 0.1 mD avg. perm) cores of Kuwait, spread over a number of wells covering a large area of over 1000sq km.
The aim of the study was to provide inputs for a detailed structural analysis of the area, with the help of reorientation of cores focusing on the geometrical and structural characteristics of each well. The reorientation procedure used a special core Goniometry process, which permits a totally hands-free 3D digitization of all planar and linear features. Reorientation of the cores is established using either the deviation data from the wells or through comparison with image log data.
In addition to the detailed integrated description of type, size, aperture and filling of fractures, a porosity/permeability model was generated after calculation of fracture frequency. By calculating the orientation and value of the permeability vectors, an indication of optimum direction of drilling was established for each well/area.
The natural fracture network obtained with open, partially-open and cemented fractures, together with induced stress-release fractures analysis, contributed to a better understanding of tectonic history and present-day stress in the studied area. A field synthesis map highlighted the main direction of all types of fractures and an actual stress map was worked out by compiling all directions of the maximum horizontal stress observed in the wells and oriented by the petal and centreline induced fractures.
The integration of the results with analyses of image log data, well log correlation data and seismic data provided critical information about the reservoir properties.
Acharya, Mihira N. (Kuwait Oil) | Chakravorty, Sandeep (Schlumberger) | Rao, Dhiresh Govind (Schlumberger) | Joshi, Girija Kumar (Kuwait Oil) | Pradhan, San Prasad (Kuwait Oil) | Rao, Narhari Srinivasa (Kuwait Oil) | Singh, J.R. (Kuwait Oil) | Dashti, Qasem M. (Kuwait Oil)
The Deep carbonate reservoirs of North Kuwait are broadly divided into deeper assemblage consisting of diagenitically modified dolomitic layer and shallower fractured-laminated tight limestone and Kerogen units. It is a challenge to establish and quantify the known phenomenon of dynamic changes in the flow path characteristics and properties of the reservoir rocks, as the natural stability condition are altered by production of reservoir fluid. The parameters of the flow path characterization become more uncertain in case of deep HP/HT digenetically altered reservoirs and fractured-tight limestone with laminated kerogen, then similar to the North Kuwait deep reservoirs.
In this study an integration of static data such as, borehole image, core and petrophysical evaluation with time lapse dynamic reservoir parameters like production, pressure data from buildup and pressure transient analysis was carried out to understand the flow path characteristic changes. A deterministic approach has been used to characterize the reservoir flow system and to estimate the fracture aperture for each time step. Thus the time dependent alternations in the flow path properties such as reduced fracture aperture and linked causative phenomena have been studied with multiple scenarios.
A detailed inventory and analysis of various well intervention operations between the time lapse measurements was carried out to distinguish the natural vs. work over induced causatives of flow path changes. This has assisted proper calibration of fracture properties for the static conditions, dynamic simulation and history matching. This workflow has also optimized the application of appropriate reservoir health checkups and remedial interventions. Cases of two representative wells completed in each of the deep reservoir assemblages are presented as examples to demonstrate the study.
Rao, Narhari S. (Kuwait Oil Co.) | Al-Doheim, Arif A.A. (Kuwait Oil Co.) | Acharya, Mihira N. (Kuwait Oil Co.) | Al-Ajmi, Neema H. (Kuwait Oil Co.) | Al-Ajmi, Saad A.H. (Kuwait Oil Co.) | Kidambi, Vijaya K. (KUWAIT OIL COMPANY) | Odreman, Allan S. (Kuwait Oil Company) | Dashti, Qasem M. (Kuwait Oil Company) | Haddou, Hamid (Schlumberger) | Oyeyemi, Oluwafemi S. (Schlumberger) | Chakravorty, Sandeep (Schlumberger) | Chimirala, Vivekanand (Schlumberger)
As part of development of hydrocarbon plays of North Kuwait, the first horizontal well was planned and drilled within the deep carbonates (over 14500ft TVD) consisting of layered Kerogen and tight limestone (average 3pu and 0.1 mD rock), divided mainly into Upper (approx. 50ft) and Lower (approx. 30ft) reservoir zones . The well profile was designed to target multiple fractures and corridors for accessing the secondary porosity and consequently increase permeability which will enhance productivity and hydrocarbon recovery.
The main challenge in the effective development of this reservoir is the ability of the well to access the permeable interconnected vertical fracture network overlain by massive Kerogene at the top and water bearing carbonates at the bottom. In addition to this known challenge was the unexpected bedding dip changes due to local structural variations observed in the dip data of the borehole image logs in the pilot hole drilled just before horizontal lateral drilling. Natural fracture clusters encountered in the pilot hole were analyzed for orientation and extent. This helped in optimizing the drainhole trajectory to achieve the main objective of intersecting as many open natural fractures as possible.
A multidisciplinary team consisting of Well Placement, Geology, Petrophysics, Geophysics and Drilling utilized 3D seismic interpretation, real-time logging-while-drilling data from distance-to-boundary (DTB) resistivity mapping techniques, Gamma image coupled with Rotary Steerable drilling assembly and placed this first horizontal well, almost entirely within the target zone of fractured Carbonate section. Despite the challenge for real-time telemetry data transmission due to high predicted pressure regime, the team was able to achieve 90% NTG lateral through seamless integration. The well trajectory was revised in real-time as needed to overcome unexpected geological challenges encountered while drilling. The integration of real-time measurements, real-time decisions, interpretation and multidisciplinary approach was the basis of success of this project.
Deep, sub-salt, tight unconventional reservoirs (average porosity of 3 p.u. and average permeability of 0.1 mD) are being targeted more aggressively for hydrocarbon potential. Till date, most of the wells have been drilled vertically or with some level of deviation through these reservoir zones with oil-base mud. The first horizontal well was planned and drilled at such great depths (over 14500 ft TVD) through alternating Kerogen-rich and carbonate formations after drilling a highly deviated pilot hole for formation evaluation and horizontal well planning. The well location was selected at a crestal area and the general direction of drilling the horizontal well was planned to be towards SW, knowing the regional trend of maximum horizontal stress direction is NE-SW. The main objective of drilling the horizontal well was to intersect the natural fracture systems extending through the target reservoirs and evaluate their potential of hydrocarbon production as an aid to develop the tight layered unconventional reservoirs.