North Kuwait heavy oil development continues to benefit from detailed study of outcrops at the Jal Az-Zor escarpment that are stratigraphic equivalents to some of their reservoirs. During the 2018-19 field season, focus was placed on recording the internal architectures of specific stratigraphic layers, developing a deeper understanding of the diagenetic processes in the basin and relating these observations to the North Kuwait reservoirs. These are all key controls on reservoir quality and connectivity. Inter-well scale heterogeneities were identified for inclusion into subsurface models to predict steam/polymer conformance and oil production better. Building on work of the 2017-18 field season when the Jal Az-Zor sequence was logged, measured, described and interpreted; units were tracked and correlated laterally for around 3km. Internal architectures of prominent layers were mapped through conventional and drone mounted photographic surveys, and satellite images. X-Ray Diffraction and thin section studies of hand samples were analyzed, to understand mineralogical controls on porosity & permeability. Integrated field trips were conducted with members from subsurface, reservoir and well-engineering disciplines, to engender common perspectives on subsurface uncertainties and development risks. They also served to close the communications gap between disciplines. Interpreted high-resolution photographic data, sediment flow direction measurements and other observations gave clues to environments of deposition and their implications for lateral connectivity for each layer. Observations on vertical connectivity between and within layers were recorded. Geological heterogeneities were considered in the context of the typical inter-well separation spacing for their implications on injected steam or polymer conformance, & water-cut. Depositional models were compiled and interpreted with regard to their implications for reservoir plumbing, H2S risk, top-seal integrity, sand production etc. Additionally, increased awareness of the stratigraphic relationships between zones was utilized to resolve correlation ambiguities for closed spaced wells in a water injection pilot and led to the development of a screening tool to predict water-coning risk in wells and informed a similar study for injected steam-conformance risk mapping. Field analogues at Jal Az-Zor are key to defining and characterizing the key genetic flow units of the heavy-oil reservoirs in North Kuwait and it is rare to have closely linked field-outcrop analogues so readily accessible. They represent an important cost-effective resource for field development and operations as they bridge the scale gap between well-derived and seismic data as they provide insight to the nature of flow unit connectivity (i.e. the reservoir plumbing – heterogeneities that matter-for-flow) in way that other data types do not. Field analogue observations therefore directly inform the grid scale permeability estimates that are used in the dynamic simulator for production forecasting and field development and operations optimization.

A series of explosions destroyed several houses at Al-Ahmadi Town in southeast Kuwait during 2010 and 2011; they were initially attributed to gas leakages from discarded old domestic gas supply system. The incidents led Kuwait Oil Company (KOC) to commission a surface geochemical survey of one of KOC's Al-Ahmadi housing blocks which was affected by the explosions. A serious gas explosion in Al-Ahmadi on the 18 th of May 2015 prompted an evacuation of a number of Al-Ahmadi houses, followed by a prolonged investigation of the source(s) of the recurrent gas leakages. This paper is a review of the published surface geology, subsurface stratigraphy, seismic structural motives and consequences of prolonged production operations of Greater Burgan Oil Field (with special focus on the surface and subsurface stratigraphy and structure of the Al-Ahmadi Ridge of Greater Burgan Oil Field, which is situated beneath the afflicted Al-Ahmadi Town) in search of natural seepage(s) rather than man-made leakage(s) of the exploding gas. The review revealed that the gas explosions were not likely caused by trapped gas in the discarded domestic gas supply network, and argue for an imperfect Greater Burgan oil trap, with inherent ancient oil and gas seepages propagated by environmental side effects of prolonged oil production operations, which attained recurrent cycles in response to climatic seasons, and probably amplified by the occasional regional earthquake seismic waves. The review concludes that under current environments and production practices, the historic trend projects an increase in the volume and number of gas seepages sites over and beyond the footprint of Greater Burgan Oil Field. Furthermore, the review recommends some habitat gas seepage mitigation measures and the deployment of mobile technologies for regular surveying and monitoring of Methane and H2S build-up in the air, and in the shallow subsurface reservoirs below the Ahmadi Town as routine risk management procedures.

Umm Gudair (UG) field is one of the major oil fields of West Kuwait asset. Minagish Oolite (MO) reservoir is the main oil producer contributing more than 95% of the current production in the UG field. The field water cut has been increasing and currently is around 60%. The increasing water cut in the UG-MO reservoir is posing a major challenge in maintaining the oil production rate as the higher mobility of water compared to the oil will lead to a decline in the oil production rate and prevent oil producing zones from contributing effectively. The increase in water cut is attributed to the rise of the OWC and the natural water aquifer that underlays the oil column and extended across the reservoir. UG-MO reservoir consists of different carbonate layers all are hydraulically connected with high vertical to horizontal permeability ratio (kv/kh) that ranges from 0.8 to 1.0. The high kv/kh ratio leads to water coning phenomena especially in the high pearmability zones. The petrophysical properties of the UG-MO reserviur shows lateral variation in permeability in each layer. The fluid PVT properties are consistent arcoss across the field with slight change vertically, the oil viscisity ranges from 2-8 cp and H 2 S and CO 2 levels are 1.5% and 4%, respectively. In order to address the increasing water production in UG-MO wells, the Field Development (FD)-UG team decided to implement Inflow Control Device (ICD) completions in deviated cased hole wells, open hole high angle deviated wells and horizontal wells. In addition, the work extended to install ICD completion in existing horizontal wells. The current total number of ICD wells in the UG-MO reservoir thirty-four To maximize the success of the ICD installation campaign, the FD team along with the completion equipment provider have undertaken key steps in developing a robust design criteria and workflow upon the completion of the assessment phase. The assessment phase included a reservoir simulation study conducted by the asset with a third-party consultancy firm to determine the increased incremental oil and the decrease in water production from ICD completion implementation across the field, in addition to a metallurgy study to identify the suitable material for ICD completion to be used in the UG-MO reservoir. The workflow included identification of the design objective for each type of well and consideration of the reservoir fluid properties and reservoir rock characteristics. The compartmentalization is based on the permeability that is estimated from recorded logs in addition to boundary mapper technology in some existing wells and the nozzles size selection is based on sensitivity runs on well-centric simulation models. The performance of the ICD completions in UG-MO is showing good results and success in the new drilled open hole horizontal wells and high angle open hole deviated wells while the results of the cased hole wells showed limited success due to associated well integrity issues (e.g. poor cement jobs and ineffective remedial jobs) and the complexity of the completion with the presence of Electrical Submersible Pumps (ESP). Moreover, the performance of ICD as re-entry in existing horizontal wells showed moderate results. The application of ICD will add value when the objective is clear, and the design criteria/ workflow is well defined and modified with time based upon the results and the performance evaluation.

The Minagish Oolite is one of the main reservoirs in the Minagish Field, Southwest Kuwait. The field is a large 4-way dip closure anticline structure, covering an area of about 90 square kilometers and with around 900feet of carbonates of the Minagish formation. The Middle Minagish member is the main reservoir, consisting of oolitic limestone with high permeability in the range of 10 to 1000 mD. The Lower Minagish member contains dense fine grained wackestones to packstones with low permeability. The Middle Minagish and Lower Minagish oil reservoirs contain highly undersaturated oil with API gravities of 28-34 °API and share a common FWL at 9950feet TVDSS. The dynamic model built along with time lapsed historical (production/injection) and well surveillance (PLT, TDT, well test) data are used for tracking the movement of injected water and gas, monitoring fluid contacts and changes in saturation with time, optimizing production and planning of new wells. Nonetheless, due high density of producers existing around the field causes mutual interference amongst the neighboring wells and surprises arise while drilling new wells. Real-time Geochemical analysis on elemental and mineral concentrations within drill cuttings/core chips, integrated with advanced mud gas data, can provide an additional analytical dataset to assess reservoir depletion and water encroachment. This advanced surface logging technology can give a better indication on water bearing zones and water encroachment when MWD/WL logs have resolution issues. When geochemical and mud gas proxies are integrated with other data sets (viz. logs, and dynamic data), they provide a better control on lithological changes and water bearing zones, throughout the entire reservoir. Integrated geochemical and advance mud gas analysis in depleted Minagish reservoir has helped to confirm zones of interest and to determine leading edge of water aquifer. Ultimately this enabled for a unique completion design. The well MN-X, object of the study, represents a valuable case where it has been possible to identify water encroachment through geochemical proxies, aiding the completion strategy.

Middle Marrat resrervoir of Jurrasic age is a tight carbonate reservoir with vertical and horizontal heterogeneous properities. The well placement over deep elonogted anticline with steep dips, geosteering and lowering of production liner are challenging, therefore the field is being developed using horizontal wells cutting across multiple reservoir layers to maximize reservoir contact and driange The low clay content in Marrat reservoirs gives low gamma ray counts, which makes the identification of reservoir layers identification difficult. In addition, the high-resistivity responses from hydrocarbon-bearing pay-zones and from the tight layers make the identification of the reservoir sweet spots difficult as well. Slim-hole magnetic resonance (NMR) logging was deployed in wash-down mode for identifying reservoir sweet-spots as a lithology-independent porosity and formation fluid characterization tool. Magnetic resonance was acquired with dual wait time enabled T2 polarization to differentiate between moveable water and hydrocarbons. After acquisition, the standard deliverables were porosity, the effective porosity ratio, and the permeability index to evaluate the rock qualities. Porosity was divided into clay-bound water (CBW), bulk-volume irreducible (BVI) and bulk-volume moveable (BVM). Rock quality was interpreted and classified based on efftective porosity and permeability index ratios. The ratio where a steeper gradient was interpreted as high flow zones, a gentle gradient as low flow zones, and a flat gradient was considered as tight baffle zones. Based on the MR flow units and fluid types (CBW, BVI and BVM), the drilled interval was classified into six compartments of high flow, one compartment of low flow, and five tight baffle zones. Accordingly, the perforation plan was optimized to fit the high flow units only. Comparing to the conventional log analysis, NMR excluded approximately 1000 ft of non-productive reservoirs, leading to a significant cost savings (250,000 USD) in perforationand production optimization. The well was drilled with a distance-to-bed boundary tool; however, enormous potential exists to use this slim MR tool as a non-radioactive sourceless solution for geosteering through reservoir sweet spots while delivering wells that are more productive safely.

The Umm Gudair field is an elongated doubly plunging anticline which bifurcates into two branches NS elongated West UG and the NE-SW elongated East UG structures with a broad saddle in between Fig1A & 1B . West Umm Gudair structure was formed during the Jurassic time and become reactivated in Cretaceous and Tertiary times. East Umm Gudair was formed during Cretaceous as evident from the thicker deposition of overlying Gotnia sediments and its unique fold geometry. A total of 28 wells targeting Najmah-Sargelu (NJ/SR) & Marrat reservoirs of Jurassic have been drilled so far in this field including one deep well in South UG in Divided Zone The Marrat Formation in Umm Gudair field is conventional reservoir with 800ft to 1000ft thick sequence comprising limestone, dolomitic limestone and argillaceous limestone with minor shale and anhydrite. The Jurassic sequence in Kuwait oil fields starts from around 12000ft and is marked by an increase in formation pressure and temperature. Above this lies the Cretaceous sequence where most of the oil field development works have been concentrated in the past. In the last two decades field development has extended to the Jurassic sequence to meet up with increasing production demands. The Jurassic sequence is marked by a series of high pressure and high temperature formations with presence of natural fractures.

The Burgan sands Formation is one of the main reservoirs of Greater Burgan field in Kuwait, producing under primary depletion since the late 1940s. Massive sands reservoirs (Lower Burgan BGSL2 and Middle Burgan BGSM) interpreted as deposited in fluvio-tidal depositional environments, alternate with lower quality and muddy interbedded sandstones (Lower Burgan BGSL1 and Upper Burgan BGSU), deposited in tidal-influenced delta settings. The complex reservoir architecture of these sand reservoirs is dependent of the sinuosity and complexity of the channel system but also on the lateral extend and distribution of the muddy deposits that will create heterogeneities and barrier to flow. In the context of future development plans of the Burgan reservoirs, the Burgan Subsurface Team implemented a workflow to identify the main barriers to flow at the interface between the massive and the lower net-to-gross reservoirs. This workflow combines geological (cores), petrophysical (Rock-Types, conventional logs) and dynamic data (pressures), to characterize the main barriers to flow between the different reservoirs. Shale barrier types and thicknesses of shales are picked and defined from logs using wireline conventional log data, and the huge database of pressures available was used to visualize and check the impact of the shale barriers on the connectivity of the reservoir and the pressure drop or continuity between the sandy units. This multiple approach allows to capture the main geological heterogeneities (shale barriers) by their type and thicknesses and combining the information with dynamic data (pressures within the reservoir zones) gave a direct link to the connectivity (pressure communication or not) between the main reservoirs. The data generated by these two approaches were used to produce maps of connectivity as well as maps of pressure differences between the main reservoirs. Modeling complex reservoir heterogeneities in clastic environments is a challenge in the oil industry. An accurate sand body distribution is crucial for a good understanding and representation of the reservoir behavior but a good representation and image of the barrier to flow is fundamental to complete the picture. In the context of the future development of Burgan reservoirs, such workflow and products will be very useful to take some decisions about the strategy to develop efficiently such type of reservoirs.

As the oil and gas industry has been investigating the challenges in identifying reservoir compartmentalization and interpreting the negative influences it generates, diverse disciplines within the oil and gas industry have presented beneficial approaches to inspect and reduce the challenges found while exploring and appraising oil fields. despite the various pieces of literature that have been published in this field stating that reservoir compartments are either structurally or stratigraphically in origin depending on the depositional facies or fault geometry. This study presents, geochemical data from twenty oil samples which are used to investigate horizontal and vertical compartmentalization of the Jawdah Field, which is located in the south of Oman. The data were intended to identify the causes of the segmentation using fluid properties. The results from each oil sample are integrated with carbon isotopes, whole-oil gas chromatography, saturates, aromatics, resins and asphaltenes (SARA) analysis and biomarkers in order to detect different variations in fluid composition that may be lead to better understanding of reservoir compartmentalization. Based on these four analyses, the research findings indicate that Jawdah oils are derived from a single source rock (Huqf oils). The identification of the Huqf source rock was based on the similarities between pristane and phytane peaks from the whole-oil gas chromatography data and the carbon isotopes for the Jawdah oils and from the Grantham (1988 ) paper. However, the API gravities in Jawdah field varied ranging from light to moderately heavy oil (20-33 API), indicating a possibility of other geological factors affected the alteration of the crude oil. Therefore, these oils were further characterized by interpreting the level of maturation and biodegradation ratios using biomarker signatures. This combination of methods has provided a more advanced method of investigating and interpreting compartmentalized reservoirs and it will lead to enhancing recovery. It was found that the Gharif and Al Khlata reservoir units are not in communication, potentially impacting well design, and field development planning.

Drillstring vibration information can be used to define the geology of the well. Some geological phenomena in horizontal wells can be revealed from drill string vibration data. Examples include faults, exiting and entering the reservoir, different lithology and rock strength. In addition, uncontrolled vibrations can also limit the optimization of drilling performance, for instance increasing the possibility of stuck pipe, affecting wellbore stability, reducing drilling tool life, and causing tool failure. This paper aims to gather vibration data from drilled horizontal wells and classify them based on the geological and lithological environment in which they were observed. Three major kinds of vibrations are resulted from horizontal drilling; axial vibration, lateral vibration, and torsional vibration. Vibration data were collected and grouped together to correlate vibration behavior to the geology of the horizontal well. These vibrations data were compared in different geological situations; for example in clastic and carbonate environments, drilling through changing lithology, exiting the reservoir, and passing through a series of faults. The correlation can then be utilized in geo-steering application. The objective of this paper is to enable engineers to characterize the vibration data according to potential risk factors that may be encountered during real-time geo-steering, and to take actions that optimize the drilling operation. Observations have revealed a strong correlation between vibration behavior and geological phenomena in drilling operations. These observations enable confirmation of various geological features from geo-steering modelling. Furthermore, adjusting drilling parameters and implementing good drilling practice would minimizes the tool exposure to excessive vibrations in order to avoid tool failure, and optimizes drilling operation. An understanding of the vibration data can also be used to help geo-steer and support the justification for any adjustment in the lateral section. This will not be a proactive adjustment but more of a reactive adjustment. An additional objective is to find the best tool configuration in certain horizontal well environments, thereby improving the drilling optimization and enabling optimum procedures by capturing the right downhole dynamics when encountering excessive vibrations. These findings will help drilling to control the well and contribute to the wellbore stability. This will be the first paper to characterize vibration behavior in relation to the geological phenomena and applying it in horizontal wells.

The sedimentation of Eocene age Dammam Formation started as a result of sea transgression above the evaporitic sequence of the underlying Rus Formation. The transgressing sea water filled the low land in coastal areas where muddy limestone was deposited and overlying brown dolomitized limestone was deposited in shallow peritdal environments. Due to continued transgression, a stratified intrashelf basin was developed where semi-anoxic to anoxic conditions prevailed and which resulted into the deposition of dark grey to black mudstone facies. Maximum flooding surface Pg20 of the Arabian Plate is correlated to lie within this zone. As the transgression subsided, shallow open marine conditions were developed where foraminifera nummulites thrived. These nummulites made shoals and banks behind which due to low energy protected setting in place deposition of calcareous sponge, Lockhartia, and nummulites occurred. Upwards, the nummulites gradual decrease and environments further shallow up resulting into the deposition of parallel laminated bioclastic limestone in inner ramp to intertidal environments. A second transgression took place in the middle of the Dammam Formation due to which a large lagoon type set up was developed. The chalky micritic facies was deposited in this quite water lagoonal setting with intertidal influence in its upper part. The proceeding yellowish brown dolomite facies has common fenestrae structures and rubbled zones along with chert nodules and stringers. This facies is very porous and was deposited in intertidal to supratidal environments. The uppermost dolostone has common chert stringers and bands and common rubbled zones developed by collapsed dissolution cavities likely related to exposure surfaces. The Dammam Formation displays two transgressive-regressive depositional sequences. The formation has excellent reservoir characteristics in the form of overall high porosity which exceeds 40% in some zones. Hydrocarbon shows in the form of bitumen remains are observed within the formation.

No two shale plays are the same. Experimental and field data shows that shale formations act differently when exposed to similar conditions. The instability of shale formation is considered one of the major problems facing drilling operations. Bit balling, cutting dispersion, washouts, and stuck pipes are some of the problems faced when drilling shale formation. Only recently, shale formation became a target for hydrocarbon production. Shale plays are the new frontier for drilling and development. When the oil price was high, it was economical to drill and produce from shale formation. Now that the price of oil is relatively low, drilling and producing from shale formation might not be that lucrative. To reduce the cost of developing shale plays, we need to understand the producing shale geomechanical properties. There have been many studies on conventional shale formation and it has helped reduce potential drilling problems in those formations. However, not all shale formations are the same, and solutions that worked with one will not necessarily work with others. That is why we need to conduct studies focused on producing shale. Two producing shale formations were used in this study they are Marcellus shale and Arabian Peninsula (AP) shale. This study is exploring the difference in swelling behavior between the one side of shale core sample that is in direct contact with fluid with the other side of shale that is not in contact with drilling fluid. This is meant to represent the swelling at the wall of the wellbore and the swelling near the wall of the wellbore. Six samples from Marcellus shale and six samples from AP shale were used in this study. Two samples from each formation were used to collect the mineralogy data using XRD/XRF tests and the remaining four samples were used in the swelling tests. For the swelling tests, the samples were half submerged in various drilling fluids where half of the core sample is inside the fluid and the other half hangs above the fluid level. Strain gauges attached to both side collect the swelling behavior continuously for seven days. Results shows that at low swelling levels the back side of the wellbore (near well bore) shrinks while the wall of the wellbore swells. However, at high swelling rate both the wall of the wellbore and near the well bore increase in size following a similar swelling profile.

The Late Albian Mauddud Formation of North Kuwait is composed of inner ramp carbonates and deltaic clastics. It hosts prolific hydrocarbon reserves in Kuwait and across the Arabian Gulf region where the reservoirs are typically the carbonate deposits. Accurately predicting the reservoir properties in the Mauddud Formation is challenging due to the non-unique wireline signatures, which result from the inherent diagenetic heterogeneity and complexity. 385ft of continuous FMI image log data, collected from a single well covering the entire formation in a north Kuwait field, has been analysed to assess its potential to characterise and extrapolate the sedimentological, diagenetic and reservoir characteristics into uncored wells. Nine distinct image facies have been defined, each of which display a specific image fabric. The image facies have been calibrated with core, thin section petrographic observations and core plug data to aid reservoir quality predictability. The study shows that gross sedimentological and diagenetic characteristics observed in the core, including laminations, patchily distributed cements and bioturbation are identifiable in the image logs. The image facies display mottled, laminated or massive fabrics. The argillaceous, fine-grained deltaic clastics, which are non-reservoir, correspond to the finely laminated image facies, however, these deposits are easily identified in uncored intervals by their distinct wireline log signature. The mottled image facies, which is associated with patchy calcite and dolomite cemented carbonates, are subdivided into six categories primarily based on the mottling size. This work establishes a systematic relationship between the mottling size and the grain to micrite matrix ratio of the deposits, and hence, the depositional setting. The finest mottles, corresponding to the smallest cement patches, are typically associated with micrite-supported lithofacies representing deposition in a low-energy inner ramp environment, while the coarsest mottles are principally observed in the grain-supported carbonate lithofacies, which are prevalent in higher energy inner ramp environments. This relationship, which possibly relates to differences in the bioturbation and/or diagenetic overprint of the deposits, is used as a proxy to interpret the depositional energy in the Mauddud Formation. Cross-laminated and massive image facies are also locally identified and are predominantly associated with high-energy shoal complex carbonates. The image facies, in part, also predict the distribution of some of the best porosity and permeability in this formation, notably in the finer mottled image facies where reservoir quality is good to moderate (HeΦ 12.5-25.8% and Kair 1.04-22.4mD). In the coarser mottled image facies, reservoir quality is heterogeneous, but can be comparably good. Using this approach, the gross rock and reservoir properties of the Mauddud Formation can be partly characterised using FMI data alone. The scheme will be refined using further core-calibrated FMI datasets from additional wells to ultimately aid the prediction of reservoir quality at field-scale.

When developing and operating oil and gas fields, a large number of engineering decisions need to be taken. These decisions range from the very high-level such as recovery mechanism, facility sizing or well count to more detailed decisions such as individual well placements, well design and completion strategies. Typically, subsurface models play a role in informing these decisions by testing their effect on forecasted production and it is generally held best practice to test them against a wide range of subsurface conditions, a range that expresses the envelope of subsurface uncertainty. Whilst these commonly held objectives are more or less universal, selecting an appropriate subsurface modelling strategy (i.e. what to model & how to model it) to achieve these objectives usually generates more divergent views. Whilst there are always various valid modelling approaches available which are both geologically and numerically valid, a good modelling strategy pays close attention to the type of the specific decisions being taken for the project and the accuracy required to take those decisions. To align these views, in decision-based modelling, business decisions and their timing were mapped to the models needed to make the estimates that inform them. Dialogue between the disciplines established the accuracy required for these estimates, and these discussions often revealed surprising opportunities to simplify processes and accelerate delivery. The outcome is a common view on a decision-driven modeling strategy that enables business decisions to be taken efficiently. This strategy, and the subsequent delivery plan that is developed from it is seen as a key to success. This paper describes the decision-based approach taken in the subsurface modelling required to support quality development decisions for the development of two of KOC's Heavy oil fields through the Enhanced Technical Service Agreement (ETSA) between Shell and KOC. In this particular application of the process, the suite of models to be built has been mutually agreed at the start by the integrated development team through a structured collaborative workshop, or Model Framing Event. A fullfield and a sector model for 2 different fields are discussed to exemplify the link between required decision and supporting modelling approach.

Drillstring vibration information can be used to define the geology of the well. Some geological phenomena in horizontal wells can be revealed from drill string vibration data. Examples include faults, exiting and entering the reservoir, different lithology and rock strength. This paper aims to gather vibration data from drilled horizontal wells and classify them based on the geological and lithological environment in which they were observed. Uncontrolled vibrations can limit the optimization of drilling performance, for instance increasing the possibility of stuck pipe, affecting wellbore stability, reducing drilling tool life, and causing tool failure. Three major kinds of vibrations result from horizontal drilling; axial vibration, lateral vibration, and torsional vibration. We collect all vibration data and group them to relate the vibration behavior to the geology of the horizontal well. This information can then be helpful in geo-steering. We compare the vibration behavior in different geological situations; for example in clastic and carbonate environments, drilling through changing lithology, exiting the reservoir, and passing through a series of faults. The objective of this paper is to enable engineers to characterize the vibration data according to potential risk factors that may be encountered during real-time geo-steering, and to take actions that optimize the drilling operation. Observations have revealed a strong correlation between vibration behavior and geological phenomena in the Kuwait oil fields. These observations enable confirmation of a variety of geological features from geo-steering modelling. Furthermore, adjusting drilling parameters and implementing good drilling practice this minimizes the tool exposure to excessive vibrations in order to avoid tool failure, and optimizes drilling operation. An understanding of the vibration data also can be used to help to geo-steer and support the justification for any adjustment in the lateral section. This will not be a proactive adjustment but more of a reactive adjustment. An additional objective is to find the best tool configuration in certain horizontal well environments, thereby improving the drilling optimization and enabling optimum procedures when encountering excessive vibrations. These findings will help drilling to control the well and contribute to the wellbore stability. This will be the first paper to characterize vibration behavior in relation to the geology phenomena in horizontal wells in Kuwait.

Horizontal drilling technology was used for the first time in the Middle Cretaceous Lower Burgan Layered Sand reservoir of Raudhatain Field, Kuwait for enhancement of oil production. The reservoir has been on production using conventional development techniques for the past 50 years. The channel sands of the Lower Burgan Layered unit were targeted. These sands are much thinner than the world class Lower Burgan Massive Sand and became an ideal target for development by horizontal drilling. However these layered sands are very prolific and are at irreducible water saturation. These sands were de an ideal target for development by horizontal drilling. However these layered sands are very prolific and are at irreducible water saturation. These sands weic and are at irreducible water saturation. These sands were deposited in a clastic coastal environment. The complex geometry and heterogeneity make these sands a real challenge to place lateral boreholes within the sand. The challenge of horizontal drilling through thin sand is to expose significantly more reservoir rocks in the wellbore which helps to increase the productivity. This paper illustrates integration of LWD, geological, geophysical and engineering data for successful placement of the lateral sections within the targeted sands to maximize oil production. In the 1 st phase of horizontal drilling, laterals in 4 wells were placed in the Lower Burgan Layered sands at different locations over the Raudhatain structure. Length of laterals varied from 650–2000ft depending on the spatial distribution and geometry of sand bodies' vis-à-vis oil column. Effective geosteering through 7–12ft thick oil sands in these wells encountered 0.5 – 1.5 Darcy reservoirs. These oil sand layers produced from 850 BOPD to 4500 BOPD on initial production testing. The success obtained in producing from these sand layers proved to be very effective and greatly enhanced the production from Raudhatain Field, Kuwait.

The well design has been changed over last 55 years of development in Zubair Formation. It is the deepest producing Cretaceous reservoir in North Kuwait. This 1,400 ft thick formation was deposited in deltaic to Paralic depositional environments with complex sand/shale sequence, structural geometry, mineralogical composition and lateral extent. Drilling wells of any profile has been more difficult than the shallower reservoirs overlying it. The wells have witnessed high non-productive time due to severe wellbore instability issues in the form of stuck pipes, tight holes, hole pack-offs and jarring/fishing operations. During initial phase lasting over 4 decades, vertical wells were drilled to drain the oil column which was thicker in most part of the Field. With water encroachments from bottom and edge, thinner pay Sands in multiple but thin pays are needed to be exploited by maximizing reservoir contact with high angle multi-lateral wells for effective production. Drilling complications are inherent in Zubair since beginning even with vertical and deviated wells. Current transition to horizontal and high angle wells was possible with integrated studies. In the first phase of mitigating stability, responsible failure mechanisms for wellbore were identified: stress induced breakouts, washouts and cavings, failure and fluid invasion associated with shale bedding planes at high deviation and osmotic pressure transmission between Zubair shales and drilling fluid system. Water sensitivity of clays and presence of micro-fractures were also studied on cores of this trouble making formation. In the second phase, calibrated well based 1D Geomechanical models; 3D structural model with high definition faults, facies models indicating lithological changes and drilling experience of latest high angle wells were integrated into a 3D Geomechanical model. The model was tested with data from several offset wells and it was capable of explaining the wellbore failure of these wells. It was used predicting mud weight window for any proposed high angle well trajectories. Mitigation measures from the study included drilling with Oil Based Mud or High performance water based mud systems with model derived mud weights, micronized sealing polymer to seal-off the laminations and micro-fractures, marble grade Calcium carbonate or resilient graphite to plug wider fractures and high salinity of mud to avoid time-sensitive osmotic flow. The integrated study was implemented and six horizontal wells and a highly deviated well have been drilled successfully. The well designs and trajectories have been modified to drill along different azimuths of stress field with turns and up dip/down dip movements. Structurally complex and faulted blocks could be crossed effortlessly. The study has given further confidence to implement an aggressive field development plan for optimal depletion of undrained areas. Current strategy is to have vertical and deviated wells also for thicker reservoirs as they have the advantage of well interventions. The paper discusses complex reservoir architecture, drilling complications and how the integrated study helped to achieve a breakthrough in development planning.

The objective of this study is to find out a novel way of overcoming uncertainties associated with successfully locating best sites for drilling infill development wells. These uncertainties are usually associated with the non-uniqueness of responses from such petrophysical properties as porosity, permeability, and water saturation created through the static reservoir modeling process, leading, in many cases, to misleading allocation of proposed infill well locations. In order to achieve this objective, a normalized combined super-property, composed of selected petrophysical properties, was created. This new property was calibrated using certain scalar factors that were given to each property in order to bring the real distribution and weightage of each of the component properties into effect. The main observation from the present study is that the novel combined super-property has proven to give more realistic and accurate allocation of proposed infill well sites. This observation was documented through practical validation of negative (wet) wells, giving misleading positive responses from conventional petrophysical properties, while giving correct accurate negative response, and vice versa, using the novel combined super-property. Incorporating this novel technique into the high-resolution stratigraphic model resulted in maximizing property distribution accuracy per reservoir layer. More accurate prediction of lateral and vertical distribution of reservoir facies and petrophysical properties in three dimensions was then achieved and resulted in outlining a number of new well locations based on this technique. The value of this novel technique lies in significantly reducing the risk of drilling negative boreholes based on static reservoir models. This is because each individual value of a property, such as water saturation, can be the result of a multitude of factors, including natural factors and/or data acquisition, processing, & interpretation pitfalls, therefore, not necessarily indicating presence of hydrocarbons. The present study reduces non-uniqueness of each individual property response using the scaled combined super-property.

Field development in complex carbonate evaporite reservoirs has been a challenge for geoscientists by using simple sedimentology based geological models. A high resolution sequence stratigraphic framework has been designed from a conceptual 3D depositional model to a deterministic predictable model. In this process framework boundaries have been fine-tuned with carbon and oxygen isotope signals and defining ichno-facies associations to map lateral continuity of member formations within Marrat sequence. As dolomites and porous grain stones are the key reservoir quality rock types for Marrat Group of formations, position of precursor lithofacies in sequence stratigraphic frame work is found to be crucial. Dolomite samples are analyzed for d13C and d18O. Upper and Lower Marrat members are characterized by thinly laminated, micro crystalline exposure dolomites and high in d18O signal which are associated to low stand packages, whereas Middle Marrat dolomites are relatively low in d18O and high in d13C are associated to high stand precursor facies. Moreover, typical ichnofacies association of porous dolomites defining vertical heterogeneity and lateral connectivity of flow zones in Middle Marrat reservoirs. The reliability of this model has been established through recent tested intervals, with production logging and formation pressure tester data integration demonstrates predictability of flow zone connectivity.

The Middle Cretaceous Upper Burgan and Wara sandstone reservoirs in the Minagish field are exhibiting variable clastic depositional settings ranging from fluvial, fluvio-tidal to tidal wave sands. The sand bodies are highly heterogeneous in terms of the stratigraphic architecture implying extensive lateral facies variations, stacked sand bodies and varying petrophysical properties. Modeling the target sand channels and optimizing subsurface well placement and geo-steering requires high resolution geological and seismic data integration in order to minimize uncertainities related to correlations of multiple auto-cyclic ravinement surfaces, channels geometry and sub-seismic fault network. Within Upper Burgan and Wara sand bodies there are different lobes that have varying degree of minerals like glauconite, pyrite and hematite with other cementing materials such as calcite and dolomite. The presence of glauconite has a strong impact on petrophysical evaluation, whereas the presence of shale poses several challenges during geosteering. Geostatistical modeling for sand distribution were integrated using seismic data, core and sedimentological models, electrofacies and petrophysical intrepretations. High resolution seismic data including pre-stack depth mighration and pre-stack simultaneous inversion have been utilized with well log curve shales and elastic impedance to trace accurately the good quality sand. High resolution sequence stratigraphic model were attempted on this complex Upper Burgan and Wara formations. The formation evaluation and geosteering challenges were addressed to ensure the successful drilling and completion of horizontal producers. The wells drilled in this complex settings are geostreed with high definition inversion based distance to boundary technology having a higher precision and accuracy of resistivity contrasts. Formation capture cross section (sigma) saturation was of great value in "mixed lithologies" of Upper Burgan and Wara as resistivity frequently polarized from the proximity to bed boundaries and in these portions traditional resistivity logs proved ineffective for saturation evaluations. In addition the real time permeability estimation using spectroscopy analysis was very beneficial to ICD design.

Hadexun oil field, located onshore west China, has been in production for over 13 years. Most of the primary oil was produced from relatively thick oil reservoirs. The development plan has now shifted toward the new resources in previously unexploited reservoirs: the ultrathin reservoir with only 0.4 to 0.8 m thickness and the 1- to 2-m low resistivity pay reservoir with an incoherent bottomwater level throughout the field. A successful drilling strategy was developed that used double-step long horizontal drilling to cover dual thin layers from a single lateral for the ultrathin reservoir and a medium single lateral for the thin low resistivity pay reservoir. An integrated while-drilling application included directional electromagnetic and wellbore imaging technologies for rigorous geological well placement and spectroscopy and sigma for lithology and fluid identification for advance formation evaluation. This integrated application has enabled us to eliminate the need for pilot-hole wells, cover dual layers by single lateral, and avoid side tracks, thus improving efficiency and significantly saving the AFE budget; accurately place the well and significantly reduce the probability of erroneous lateral placement along the thin target layers and avoid drilling into water zone, thus optimizing reserve recovery; optimize the outline of future horizontal drain locations; and economically develop the new resources in previously unexploited reservoirs.