Dashti, Jalal (Kuwait Oil Company) | Al-Awadi, Mashari (Kuwait Oil Company) | Moshref, Moustafa (Kuwait Oil Company) | Shoeibi, Ahmad (Geolog International) | Pozzi, Alessandro (Geolog International) | Estarabadi, Javad (Geolog International)
The Middle Jurassic strata of the NE Arabian Plate compose part of the largest world-class petroleum system, with more than 250 billion barrels of proven hydrocarbons. The Najmah Formation, one of those productive strata located in Kuwait, represents a transgressive deposition within a deep basinal settings and anoxic environments; with its black shales interbedded with bituminous limestones the Najmah Formation works as both reservoir and source rock. Due to its organic richness and maturity, the middle Jurassic formation can be considered the best potential conventional/unconventional play in the Kuwaiti Province.
Evaporates of Gotnia, a HPHT formation overlaying the Najmah reservoir, are dealt with high mud weight (19-21 ppg), to counter the high pressured patches. The identification of Najmah stratigraphic top is crucial for setting the casing point, then reducing the mud weight for the final drilling phase. Missing this critical casing point may lead to several rig NPT and related operational cost increments, such as cement jobs and, in extreme cases, may lead to missing and abandoning the well. When the standard investigation methods, as the optical microscopy, or Gamma Ray failed in identifying the Najmah top, due to the similarity between its limestones and those of Gotnia Formation, the ED X-ray fluorescence (XRF) and X-ray diffraction (XRD) established distinctive formations geochemical ‘fingerprints’, as well as their sedimentary patterns, providing absolute certainties about the casing point position despite a misleading stratigraphy.
The technique of Chemostratigraphy, applied in this study on five exploratory wells, can increase the value of such geochemical fingerprints, providing not only applications as critical casing points ID but also a means to unify stratigraphic schemes, i.e. develop stable reference stratigraphic frameworks: changes in rock geochemistry reflect changes in the relative sea level, thus sediment supply/accommodation, oxygenation and diagenetic conditions.
Once inside the Najmah Formation, the elemental and mineralogical patterns point out different formation sublayers, corroborating many sedimentological and stratigraphic evidences obtained from outcrops and cores analyses. Some redox-sensitive trace metals are delivered to the sediment in presence of organic matter (Ni, Mo, V and U) under anoxic-euxinic conditions and tend to exhibit covariation with TOC, highlighting the best pay zones in the Najmah Kerogen sublayers. Some other metals such as Mn, Fe and Zn, in carbonate sequences, can evaluate the amount of carbonate cement (sparite) among the microcrystalline matrix (micrite); such metals, correlated with mud gas concentration, reveal the most porous sections within calcareous sublayers.
Having access to more detailed rock properties allow for one time decisions making, such as the identification of casing/coring points and the characterization of a reservoir in all its sublayers. Chemostratigraphy has led the operational team to minimize NPT and related costs, the completion team to the right well profiles and the production team to a better overview of the reservoir.
Al-Shamali, Adnan (Kuwait Oil Company) | Mishra, P. K. (Kuwait Oil Company) | Verma, Naveen K. (Kuwait Oil Company) | Quttainah, Riyad (Kuwait Oil Company) | Al Jallad, Osama (Ingrain Inc.) | Grader, Avrami (Ingrain Inc.) | Walls, Joel (Ingrain Inc.) | Koronfol, Safouh (Ingrain Inc.) | Morcote, Anyela (Halliburton)
In Kuwait, the Najmah source rock is characterized by a complex diagenetic history and depositional variability. Accurate determination of the porosity and permeability logs is essential for improved petrophysical evaluation, which may not be properly performed using conventional methods. This complexity makes the conventional evaluation methods alone insufficient to determine porosity and permeability logs accurately. A major goal of this study was to produce high-resolution porosity-permeability logs for Najmah Formation using advanced digital analysis and geochemistry measurements.
Sixty (60) feet of continuous core were analyzed from an oil field in southwest Kuwait. The analysis started with dual-energy x-ray CT scanning of full-diameter whole core and core gamma logging. Plug-size samples were selected to represent the varying porosity and organic matter content along the entire core length. Two-dimensional Scanning Electron Microscopy (2D SEM) and three-dimensional Focused Ion Beam (3D FIB-SEM) images were acquired and analyzed to accurately determine the organic matter content and porosity. Matrix permeability was directly computed from the 3D FIB-SEM images using the Lattice Boltzmann method. The SEM porosity was calibrated by determining the amount of movable hydrocarbons at in-situ reservoir conditions based on geochemical analyses (XRF, XRD and LECO), pyrolysis indices, PVT data and adsorption isotherm experiments.
The digitally obtained porosity and permeability data showed a unique trend that was used to produce permeability at the core level. The integration between digital analysis and geochemistry data increased the estimated porosity and confirmed higher mobile hydrocarbon in the reservoir in comparison with the measured data at the surface. This produced a new porosity-permeability trend that was more representative of the reservoir conditions and caused a significant increase in the rock permeability.
The integration between the digital SEM analysis and the geochemical measurements was critical to estimate in-situ porosity and permeability characteristics of the tight formation under study. Moreover, this analysis provided an important tool for obtaining different high-resolution porosity and permeability logs based on various porosity considerations (effective, organic, inorganic, clay). This would lead to higher accuracy in determining reservoir properties for improved quantification of reserves and productivity.
Richard, Pascal (Shell Global Solutions International BV) | Lamine, Sadok (Shell Global Solutions International BV) | Pattnaik, Chinmaya (Kuwait Oil Company) | Al Ajmi, Neama (Kuwait Oil Company) | Kidambi, Vijay (Kuwait Oil Company) | Narhari, Rao (Kuwait Oil Company) | LeVarlet, Xavier (Shell Kuwait Exploration And Production BV) | Swaby, Peter (Swaby Software Limited) | Dashti, Qasem (Kuwait Oil Company)
The North Kuwait Carbonate (NKJG) reservoirs are currently under development by KOC (Kuwait Oil Company). The appraisal and development of the NKJG offer challenges such as lateral variations in reservoir quality, tight to very tight reservoirs and natural fracturing to a varying degree spatially. The presence of open, connected fractures is one of the key elements to achieve a successful development. Also, the presence of fracture corridors increase the risk associated with drilling. Numerous fracture modelling studies have been supporting both appraisal and development strategies of the fields.
A structural evolution model has been developed based on field observations and linked to the regional phases of deformations. Detailed fracture characterization using static BHI (bore hole images) and core data as well as dynamic data has been achieved. Small scale detailed DFN (Discrete Fracture Network) in support of planning and drilling activities of future appraisal wells has been carried out. Full field DFN in support to production history matching and forecast has been completed. The core and pressure transient analysis data have been used to calibrate the permeability and porosity of the DFN property ahead of the dynamic simulation work.
This paper illustrates some examples of best practices of the various study components with a focus on core to BHI calibration, fracture porosity calibration using core data and calibration of DFN models using pressure transient analysis data.
Numerous oil and gas reservoirs in Kuwait are suffering from H2S contaminations. The H2S concentrations in the affected reservoirs vary significantly from low ppm ranges up to 40%. The H2S concentration levels are related to the generation processes. The high H2S concentrations observed in the Lower Jurassic reservoirs can be related to the TSR process. The dominant H2S generation process in the Upper Jurassic and Lower Cretaceous reservoirs is the thermal cracking of the organic sulphur compounds (OSC) occurring in the Najmah and Sargjelu source rocks. The H2S contaminations observed in the Cretaceous reservoirs show indications of multiple H2S sources. The bulk of the H2S in these reservoirs is generated in situ by the BSR process. In some fields clear indications for H2S migrated from deeper horizons e.g. via faults are observed.
H2S contaminations are also observed at the top site facilities at various stages of the production process. The source for those contaminations is only partly in the subsurface. In several cases a distinct increase of the H2S contaminations of the fluids on its way from the reservoir well to the processesing facilities is observed.
New sampling and analytical technologies tailored to the H2S problematic have been developed, which support the selection of the appropriate mitigation or remediation strategy. The utilization of modern low cost DNA sequencing technologies for the analysis of the bacteria and archea species provide essential information for the design of appropriate chemical cocktails for the mitigation.
Reservoir modeling and forecast technologies have been developed to predict the development of the H2S concentrations in a reservoir. However, for a reliable forecast - irrespective which modeling system or tool is applied - the understanding of the H2S generation process is essential. Furthermore good quality and reliable H2S measurements are mandatory for the history match.
The mitigation and remediation of H2S is a major cost factor in the field development and operations. Field souring i.e. the increase of the H2S concentration during field life is the worst case scenario, which could cause major investments to assure field production. Not only the costs for the H2S treatment materials (e.g. biocides, nitrate) but also the investments in corrosion inhibitors, H2S resistant pipes, valves, filters, and the upgrade of the processing facilities have a large financial impact. Furthermore HSE related measures and required safety and monitoring systems are increasing substantially the operation costs.
In view of KOC's ambitions to increase the oil production by 20% by 2020 and the subsequently expected increase of H2S production, a contry-wide coordination of the treatment concepts for the H2S could improve the efficiency of the mitigation operations and could potentially reduce the investments and operation costs related to the sour gas issue.
Rajagopal, Rajesh (Kuwait Oil Company) | Al-Jenaie, Jarrah (Kuwait Oil Company) | Jaseem, Mohamed Hafez (Kuwait Oil Company) | Arasu, Raju (Kuwait Oil Company) | Das, Surajit (Kuwait Oil Company) | Majumdar, Sanjay (Kuwait Oil Company)
Summary Seismic multiples create false events on seismic sections, which degrade the accuracy of structural and stratigraphic mapping of the Jurassic and deeper Pre-Jurassic reservoirs in onshore Kuwait. Most of the multiple attenuation techniques use prestack data, and it is often concluded that once the data is stacked, we cannot do any further multiple attenuation. Most of the multiples in the seismic data are generated from some particular layers occurring above the target reservoir intervals. Once these multiple generating layers are identified, then it is easy to model these multiples. This paper presents a case study of attenuating multiples on stacked seismic dataset, North Kuwait, using the impulse response of the primaries and the interbed multiples at well-to-seismic calibration stage and further at the inversion stage.
Callovian-Kimmeridgian organic-rich carbonates (Hanifa Formation and equivalents) are exceptional source rocks that have generated substantial volumes of hydrocarbons and charged prolific conventional reservoirs across the Middle East. This stratigraphic interval is now also under appraisal as an unconventional play with a vast resource potential. An unconventional screening workflow, assessing organic-carbon content, maturity, thickness, and depth, has identified a considerable area that appears to be viable as an exploration target.
To gain an understanding of the controls on sweet-spot distribution in this frontier unconventional play, it is necessary to consider a producing analogue. The Eagle Ford play in the Western Gulf, USA is commonly considered as a reservoir completion analogue because it has a comparable carbonate-dominated composition. However, the Eagle Ford play does not appear to be a pertinent exploration analogue because the geological criteria that control the distribution of sweet spots are fundamentally distinct from the Hanifa play. In this study, the emerging Vaca Muerta play in the Neuquén Basin, Argentina is considered to be a useful exploration analogue because its depositional architecture, stratigraphic variability, and composition are comparable to the Hanifa play.
Sweet spots in the Vaca Muerta play are controlled by mechanical stratigraphy, which is related to the architecture and stratigraphic variability within the depositional system. Interval-specific production data from the Vaca Muerta Formation demonstrates that the best-performing units are not necessarily the most organic-rich, but relate to units with high frequency, cyclical intercalation of organic-rich units, and more brittle carbonate-dominated target horizons. The integration of seismic, well log, geomechanical, and production data demonstrates that sweet spots occur within progradational packages on the carbonate ramp. The best-performing areas (e.g., northwest sector at Loma Campana Block) intersect the lowstand systems tract where forced regression of the carbonate ramp induces reworking and detrital carbonate input into the anoxic basin.
By upscaling these concepts, an unconventional exploration model can be formulated to guide regional sweet-spot prediction. The unconventional exploration model uses gross depositional environment maps, within the predictive framework of a sequence stratigraphic model, to identify the aerial extent of geomechanical sweet spots within each defined eustatic sequence. This is a valuable tool that can be used in conjunction with regional seismic data to identify potential sweet spots in both the Vaca Muerta play and the analogous Hanifa play.
In Kuwait, the traditional approach to Field Development has been to drill wells, whether Vertical or Horizontal, Single or Dual, with completions dedicated to either Production or Injection. However, as increasingly more wells are being drilled to develop the stacked reservoirs, surface infrastructure is growing in complexity with regard to Production Flowline routing, Gathering Facility location, Satellite Manifold placement, Water Injection distribution lines routing, and access road construction. Also, since the reservoir stack is a combination of areally extensive Carbonates overlying shale & channel sand sequences, optimum surface locations of Injectors for one reservoir is now increasingly conflicting with the optimum surface locations for the Producer of another reservoir.
The North Kuwait team presented options that could reduce the requirement for excessive wellbores for both new Producers and Injectors. One of which is the utilization of a single wellbore to both Produce Oil from one reservoir and Inject Water into another reservoir simultaneously. This novel approach utilized the most popular Dual Completion equipment, but rather than produce or inject concurrently from separate reservoirs or layers, production & injection are achieved simultaneously through either tubing string. Tubing movement calculations were made to ensure that the resultant axial tubing forces exerted by simultaneously injecting cold water and producing hot reservoir fluid would not cause the Dual packer to prematurely unset.
This unique completion has several advantages which include the production acceleration from an adjacent reservoir/layer that would have been postponed for the life of the Injector and the elimination of the drilling of a new producer to access the oil from an adjacent reservoir/layer to the target injection zone. Additionally, the elimination of the drilling of an Injector well if its optimum subsurface location is close to, or coincides with, an existing Producer from an adjacent layer, and the reduction in access road construction and location preparation costs. This strategy will significantly reduce Unit Development Costs while concurrently ramping up production levels. With simple conversion workovers, rather than drilling new wells, Oil Production potential that is presently unexploited in dedicated Injector wells can immediately be realized. Pressure support Injection can be initiated as soon as distribution injection lines are made available via similar conversion workovers.
Acharya, M. N. (Kuwait Oil Company) | Joshi, G. (Kuwait Oil Company) | Al-Mershed, A. (Kuwait Oil Company) | Al-Otaibi, F. (Kuwait Oil Company) | Al-Azmi, Mejbel (Kuwait Oil Company) | Dashti, Q. M. (Kuwait Oil Company) | Wiryoutomo, M. D. (Schlumberger Oilfield Eastern Ltd) | Chakravorty, S. (Schlumberger Oilfield Eastern Ltd)
Is the seal leaking? Does the cap rock strata have full integrity? Is the system in equilibrium over geological time? Are there any natural flow dynamics prevalent even when the reservoirs are virgin? These are few Frequently Asked Questions (FAQs). These FAQs becomes very critical for any geologically complex and structurally challenging deep high pressured and high temperature, unconventional reservoirs. The unconventional tight-fractured carbonates and kerogen resource-play reservoirs of Deep North Kuwait Fields, underlain by anhydrite-salt layers of cap rock, have given rise to similar questions in the early stages of development for successful economic exploitation and field development.
Stoneley waveform data can be used to identify fractured interval and estimate open fracture’s width in a borehole. The method uses direct and reflected Stoneley wave arrival measured by the full waveform array sonic tool. The Stoneley wave, when passing a fracture which is intersected across a borehole, applies pressure to the fluid in the crack. If the fracture is open, some fluid will flow into it and will result in increasing pressure drop in the borehole. The magnitude of the pressure drop depends on the fracture opening and extent thus giving an indication of fracture permeability. Dropped of pressure attenuates the direct Stoneley wave and also generates reflected Stoneley wave.
The spectral noise log (SNL) logs are designed to identify different fluid flow mediums in the reservoirs, cross-flows behind casing and tubing and casing leaks by spectral analysis of recorded noise signals. Qualitative and quantitative analysis of SNL data require filtering techniques that can extract statistically spectral components, and the useful signals expected to be confined to a near well bore region of investigation. The two data sets complement each other.
The paper discusses the integrated results of a couple of wells, where the SNL data is complemented with open-hole full range Stoneley waveform data to answer some of these questions. Thus taking considerable lead for reservoir management, field development planning and effective well integrity management and surveillance plan.
Acharya, M. N. (Kuwait Oil Company) | Al-Mershed, A. (Kuwait Oil Company) | Narhari, S. R. (Kuwait Oil Company) | Al-Azmi, M. (Kuwait Oil Company) | Dashti, Q. M. (Kuwait Oil Company) | Chakravorty, S. (Schlumberger Oilfield Eastern Ltd) | Abdulkadir, R. I. (Shell Kuwait E&P) | Prosvirkin, S. (TGT Oil & Gas Services)
Kuwait Oil Company is developing deep tight fractured carbonate and kerogen rich shale gas plays in northern part of Kuwait. Understanding the flow medium is important to resolve ingress of offending fluids such as water and salt during production history in the vertical/deviated wells of this play.
These unconventional reservoirs have been established to be hydrocarbon producing in several prolific vertical producer wells, without having such early water breakthrough. The tight fractured limestone reservoir is sandwiched between salt-anhydride sequence above (Gotnia cap rock) and Kerogen rich carbonate below. A dedicated casing is set at the top of limestone reservoir with the main objective of isolating the Gotnia section prior to opening the reservoir, as some sequences of anhydrites with calcite stringers in Gotnia are high pressured and prone to high water, CO2 and H2S. Based on the current understanding, main source of offending fluids is suspected to be the overlying Gotnia formation, which has limestone stringers.
Fracture studies from several conventional cores and image log data could not conclusively infer through going fractures into Gotnia, although many sub-vertical fractures of different nature have been observed and interpreted in the reservoir section in these logs.
This paper highlights the approach for detection and characterization of flow mediums, in the near well bore region (NWR) within a diameter of investigation of 3 meters or 10 feet. Results of spectral noise log (SNL), high precision temperature (HPT), pressure and natural radioactivity (GR) of a vertical well logged in shut in and flowing mode helped in understanding different flow mediums such as channel flow, fracture flow and reservoir flow. Thus the detection and characterization of different flow path systems with respect to their spatial dimension and their interactive flow contribution could be ascertained with high confidence.
Richard, P. (Shell Global Solutions International B.V.) | Pattnaik, C. (Kuwait Oil Company) | Al Ajmi, N. (Kuwait Oil Company) | Kidambi, V. (Kuwait Oil Company) | Narhari, R. (Kuwait Oil Company) | LeVarlet, X. (Shell Kuwait Exploration And Production B.V.) | Guit, F. (Shell Kuwait Exploration And Production B.V.) | Dashti, Q. (Kuwait Oil Company)
The North Kuwait Carbonate Reservoirs (NKCR) are currently under development by KOC (Kuwait Oil Company). The appraisal and development of the NKCR offer challenges such as lateral variations in reservoir quality, tight to very tight reservoirs and natural fractures with a high degree of spatial variations. The presence of open, connected fractures is one of the key elements to achieve a successful development. Also, the presence of fracture corridors increases the risk associated with drilling. Numerous fracture modelling studies have been supporting both appraisal and development strategies of the fields.
This paper illustrates how small sector scale detailed DFN (Discrete Fracture Network) can support the planning and drilling activities of future appraisal wells.
A series of detailed DFN models has been built around existing wells. These DFN models are based on a thorough structural understanding combined with a detailed fracture characterisation using bore-hole image (BHI) and core data around the wells of interests. In addition to the fracture characterization work, mechanical stratigraphy has been developed using E-facies and geomechanical logs. Fracture connectivity analysis has been carried out to calibrate the DFNs to the static and dynamic well data. DFN models have also been created around appraisal well locations based on the calibration with the existing wells. These DFN models are now being used to communicate with drilling in order to illustrate the potential distribution of fracture corridors in the sub-surface. These DFN models are also helping to improve the placement of the planned wells with respect to their associated risks and objectives.