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The State of Kuwait is currently appraising and successfully developing the tight carbonates reservoirs of Jurassic age, which have very low matrix porosity and permeability. These reservoirs are affected by several tectonic events of faulting and folding, resulting in the development of interconnected natural fractures, which provide effective permeability to the reservoirs in form of production sweet spots. The objective of the study was to characterize the natural fractures and identify high permeability sweet spots as being appraisal drilling locations in a discovered field with tight carbonate reservoirs. An integrated approach was undertaken for building a discrete fracture network model by characterizing the developed faulting- and folding-related fractures and combining all subsurface data from multiple domains. The reservoir structure has a doubly plunging anticline at the field level that is affected by several strike-slip faults. The faulting-related fractures were characterized by generating multiple structural seismic attributes, highlighting subsurface discontinuities and fracture corridors. The folding-related fractures were modelled using structural restoration techniques by computing stresses resulting from the anticlinal folding. The fracture model was built in addition to the 3D matrix property model for this tight carbonate reservoir, resulting in a dual-porosity-permeability static model. Analogue data was used to compute fracture aperture and expected fracture porosity and permeability, to identify the sweet spots. Structural seismic attributes such as Ant Tracking and Consistent Dip were successful in highlighting and identifying the fault lineaments and fracture corridors. The seismic discontinuities were validated using the fractures interpreted in the image log data from the predrilled wells before being input into the fracture model. Paleo stresses, derived from structural restoration, were combined with the reservoir facies and geomechanical properties to gain important insight into predicting fractures developed due to folding. Several fracture aperture scenarios were run to capture the uncertainty associated with the computed fracture porosity and permeability. Based on the results, several sweet spots were identified, which were ranked based on their extent and connected volumes of the various permeability cases. Identifying these sweet spots helped make informed decisions regarding well planning and drilling sequence. High-inclination wells aligned parallel to the present-day maximum stress direction were proposed, which would cut across corridors of the predicted open fractures. Through this study, comprehensive fracture characterization and fracture permeability understanding of the tight carbonates in the field under study were successfully achieved. This workflow will be useful in exploratory or appraisal fields with tight carbonate reservoirs.

Producing unconventional reservoirs characterized by low porosities and permeabilities during early stages of exploration and field appraisal can be challenging, especially in high temperature and high pressure (HPHT) downhole conditions. In such reservoirs, the natural fracture network can play a significant role in flowing hydrocarbons, increasing the importance of encountering such network by the boreholes.Consequently, the challenge would be to plan wells through these corridors, which is not always easy. To add to the challenge, well design restrictions dictate, the drilling of only vertical and in minor cases deviated wells. This can reduce the possibility of drilling through sub-vertical fracture sets significantly, and once seismic resolution is considered, it may seem that all odds are agents encountering a fracture network.This article addresses a case where a vertical well is drilled, in the above-mentioned reservoir setting, and missed the natural fracture system. The correct mitigation can make a difference between plugging and abandoning the well or putting it on production.The technique utilized is based on a borehole acoustic reflection survey (BARS) acquired over a vertical well to give a detailed insight on the fracture network 120 ft away from the borehole. Integrating this technique with core and high-resolution borehole image logs rendered an excellent match, increasing the confidence level in the acoustically predicted fracture corridors.Based on these findings new perforation intervals and hydraulic stimulation are proposed to optimize well performance. Such application can reverse the well decommissioning process, opening new opportunities for the rejuvenation of older wells.

Increased water cut represents one of the biggest challenges to the oil industry, with more than 75% of the produced fluid being water that brings an increased cost per barrel of oil through water handling, scale deposition, corrosion, and mainly the bypassed oil reserve. Water shut off solutions range from mechanical solutions like bridge plugs to chemical treatments that include cement, resins and polymer gels. Cement applied as a plug or a squeeze treatment is often the preferred option to the operating company for isolating unwanted production intervals near the wellbore, and crosslinked polymer systems are also commonly used when deeper penetration is required. However, the success of these treatments often suffers from mixed fluid quality, zonal isolation (cementing quality), proper placement, numerous downhole conditions and more importantly backflow of unset cement slurry or immature gels while cleaning up leftover slurries in the wellbore or pulling out the work string after the treatment. In this paper, a new system based on a single nano-additive is described to shut off a water zone in a South Kuwait regional oil producer. The new system, which does not require curing but acts rapidly in porous media, addresses the concern of backflow associated with unset cement or crosslinked polymer fluids. The objective of this treatment was to seal off the upper zone that produces mostly water, reduce overall water cut from 90% to less than 10%, and test the productivity of the lower zone. The well configuration does not allow zonal isolation without a rig, so cement and other known chemical treatments were unsuitable for this application. Eighteen barrels of the water shut-off treatment was pumped through coiled tubing (CT) and injected into a 34 ft zone resulting in nearly immediate response through increased wellhead pressure. The injection was resumed every three to four hours to ensure a complete sealing of the target interval. The fluid starts workingupon injection into porous media but always remains as liquid phase when kept in the wellbore or surface tanks, so there is no concern about sticking or plugging the coil. The operational time was reduced compared to normal water shut off jobs, and the single additive fluid is low viscosity making surface mixing simple. The novelty of this water shut-off system is efficient sealing of a high permeability formation with minimal fluid and achieving a drastic water cut from 90% to1%. This new system, unlike polymer-based systems, doesn't degrade with temperature, water hardness or salinity, and plugging of the porous media works by acompletely different mechanism leading to a more robust barrier against water production with reduced interventional risk.

The current competitive market conditions in the oil industry and company’s shoestring budgets call for methods to recover crude from wells with minimum costs. This paper focuses on the design, rigless installation, and successful results of a sucker rod pump (SRP) system after the failure of the existing progressive cavity pump (PCP). The subject well had a PCP at 4,248.05 ft. setting depth failed after 60 days due to a broken rotor. Attempts to fish the parted rotor were unsuccessful. To avoid a workover rig and to reduce non-productive time (NPT), a SRP system with an insert pump anchor was set over the failed PCP system at 4,028 ft. via a flush by unit. A tubing punch job from 4,085 to 4,145 ft. was done for allowing the fluid entering the tubing and passing through the SRP system. Running a SRP with an insert pump anchor enabled the pump to be set at any depth inside the tubing, above the failed PCP system. Successful installation of the SRP system reduced NPT and standby costs, and eliminated the need for a workover rig. While running the SRP system, the production enhanced by 50% more than the PCP’s maximum recorded rate. On the other hand, the pump can be retrieved and/or the artificial lift method can be converted later on without the requirement of a workover rig. In Burgan field, Kuwait, the first rigless installation of a sucker rod pump over a failed progressive cavity pump has turned into the reference for methods of how to recover oil when other artificial-lift systems fail.

Drilling operations within the oil and gas industry can be very complex and expensive; and while directional drilling and well placement are critical in the well delivery, additional complexities and time consuming processes must be followed to drill and deliver the wells, as desired, following the trajectory. It is desirable to evaluate the implementation of best practices to improve well delivery efficiencies, minimize nonproductive time and transfer lessons learnt from one well to another. Lean thinking has existed for many years; it was first developed within the automotive industry in the 20th century, and then began to be applied within other industries. The lean concept is based on eliminating waste by more closely examining processes to identify and eliminate waste in every stage of a process, thus improving efficiency and lowering production costs. Lean thinking has become popular amongst senior level management within the oil industry, and has become part of core strategies for many companies, with dedicated resources to systematic lean implementation in many areas of business with clear goals and objectives. An operating company began lean implementation in different areas. An opportunity to lean and standardize the development drilling process was recognized in the south of Oman, with improvements to be replicated in the other fields, as applicable. This paper describes the implementation and outcome of a lean philosophy for directional drilling. By adopting and engaging in simple lean thinking, improvements can be achieved in many areas. The value of lean implementation and workflow is presented. Also discussed are results obtained that led to significant savings in the survey time, contributing to faster well delivery and improved efficiencies.

While drilling through a reservoir, a lot of valuable information can be obtained from mud logging to support formation evaluation. Field data will help wellsite geologists, petrophysicist and reservoir engineers to predict reservoir quality, fluid contacts and reservoir permeability based on formation gases detected while drilling. This study discusses some examples from exploratory wells that have recently been drilled in Kuwait. Gas readings were recorded while drilling through Cretaceous and deep Jurassic formations to evaluate hydrocarbon content using Advanced Gas Chromatography. The primary components of the system utilized are: a constant volume gas extractor, a gas sample flow control system, and a high resolution chromatographic system. To interpret the findings Gas readings are monitored by a complex system which provides real-time continuous measurements of the concentration of formation gases from very light components such as methane, to heavy components such as C6, C7 and C8 hydrocarbon species, comprising n-hexane, n-heptane, n-octane, benzene and toluene. Formation gas is considered as the first indication of a reservoir's fluid characterization and reflects the extent of the productivity of the well. Geochemical ratios and equations can enhance the interpretation of field data and give the first indication of zones of interest that need further evaluation. The integration of the gas data along with the drilling parameters (ROP, ΔFlow) can be of valuable inputs to quantify the Rock properties such as porosity and permeability, this new approach can extend the utilization of gas data not only for formation evaluation and fluid characterization but also for formation petro-physical structure. To take advantage of the field data, the gas readings are plotted on a depth log, which can be easily integrated with other data. Geochemical equations are plotted against depth and lithology to determine fluid type, contacts and evolution.

We present a case study with regard to multiple contamination of seismic data in post-stack 3D seismic data in the North Kuwait Gotnia subbasin, which holds very good hydrocarbon potential within Pre-Cretaceous reservoirs but faces considerable challenge in reservoir characterization because of its multiple contamination. This study attempted to focus mainly on the Pre-Cretaceous carbonate reservoir around the KM structure. The main challenge is to deal with interference of 5th or 6th order peg-leg multiples with primary signals at the reservoir level. Peg-leg multiples are instances of short-path, multiple reflected seismic energy that can directly impact the seismic inversion results, facies mapping, structural interpretation, and hence depth prediction. The improved approach to multiple attenuation could be demonstrated by a pilot processing using the following techniques on select locations. The new technique delineates a spatial an area which may be contaminated with multiples in post-stack 3D seismic data. First step tool for interpreter.Key elements gained from this method to implement multiple mitigation measures, which can reduce the multiple-contamination effect in post-stack data are: ∘Identifying spatial area of contamination by observation by horizon flattening.∘Nature of amplitude contamination over structurally favourable locations.The interference may indicate the nature of multiple contamination. This method is subject to testing. A new approach to identifying and interpreting multiple contaminated primaries in full-stack seismic data provided a better interpretation of data for the North Kuwait Gotnia sub-basin. It revealed need for more multiple modeling and vertical seismic profiling (VSP) in all wells. However, it also provides a methodology for reprocessing for all available 3D seismic data through multiple mitigation that can improve seismic inversion, reinterpretation, geomodeling on newly processed 3D seismic data

This paper presents a methodology which allows performing a real time characterization of the conductive natural fractures permeability intercepted by the bit while drilling. Such fractures are detected by monitoring continuously flowing from the wellbore into surrounding formations and the mud losses at the rig-site using flow-meters measuring both the ingoing and the outgoing mud flow. Moreover, when drilling naturally fractured reservoirs, mud loss data provide one of the most effective means to assess the existence of conductive fractures intercepting the wellbore and therefore to identify potentially producing intervals. The patterns in the variations of these volumes are analyzed to identify open fractures. The advanced Flowmeter has increased the resolution of the mud flow measurements. It has enabled the authors to assess the flow quantitatively and relate mud flow anomalies with the presence of open fractures down hole in the trial exploratory well. The mud flow anomalies were validated with surface drilling parameters and gas indications. It was observed that the open fractures were associated with increase in torque and gas indication. The mud flow anomalies also provide crucial information for early kick or losses detection in high pressure gas wells because a better accuracy and a quicker response in detecting kicks and losses can be achieved by monitoring the changes of the mud flow rate by using flow meters measuring the inflow and the outflow mud rate, respectively. Method and Theory The most commonly used techniques to detect the mud losses consist in monitoring the level of the mud pits with acoustic, floating sensors and/or using paddles set inside the flow line that measure the return mud flow rate with a small degree of accuracy. The traditional Flowmeter provides a simple qualitative fluctuation in mud flow. In contrast this advanced Flowmeter works on the principle of converting mudflow out in to an analog signal which represents the volume of mud.

KOC is having Booster stations facilities to compress the gas from LP and HP pressures to Very High Pressure and transport to KNPC plant for heavier extraction. BS-140 and BS-150 facilities are designed to dehydrate wet gas to 20.90 Lb. /MMSCF and 21.90 Lb. /MMSCF as part of COSTAIN improvements in 1999. BS-140 & 150 facilities are struggling with high glycol consumption and leading to higher operating costs for KOC. In order to provide solutions for the long standing issues like higher Glycol consumption and causing indirect impact on Operating cost of the Process facilities, Six Sigma approach selected for optimizing the Gas Dehydration unit performance in BS-140 facilities. Team conducted detailed analysis and various process reviews carried out and BS-140 TR-II selected as role model for implementing the operational parameters modifications and monitored the summer period Glycol consumption. Team selected Six Sigma process plan to achieve good results. As part of Six Sigma approach, MAIC (Measure, Analyze, Improve and control) action plan implemented to meet the objectives. After the improvements resulted 33% glycol consumption reduction (Revenue of US$ 565,049 Approx.)In normal operating scenarios without any business process operations interruption by implementing minor operational improvements.

Kuwait Oil Company (KOC), an upstream subsidiary of Kuwait Petroleum Corporation (KPC), ranks amongst the major oil companies of the world. However, due to an inherently low GOR of its flagship oil fields, Kuwait has not been very gas-rich and has been compelled to practically utilize all of its produced gas in order to meet its needs. The gas utilization presently ranges in excess of 97%, produced at the grass-root level (flaring < 3% of produced gas). The plan is to increase the gas utilization to over 99%, predominantly by reducing the flaring further down to < 1% by 2011-12. Utilization of WK (sour) rich gas is KOC's biggest challenge. This paper intends to bring out KOC's approach in meeting the gas challenge and maximizing the utilization of its gas. KOC's total gas business is managed by two separate groups. While one manages the associated gas from its three legendary primary producing assets viz. South & East Kuwait (S&EK), North Kuwait (NK) and West Kuwait (WK), the other group manages the non-associated gas from the newly exploited ‘Jurassic’ fields. The asset facilities of the former are owned and operated by KOC while those of the latter are leased under build, operate & maintain contracts. WK & Jurassic gas are significantly sour. Upstream gas handling & processing is restricted to gas compression & dehydration, metering and transportation. Gas sweetening, sulfur recovery and extraction of LPG and other lighter / heavier value added are carried out in KPC's downstream subsidiary Kuwait National Petroleum Corporation (KNPC). However, Jurassic non-associated gas is sweetened down to 4 ppm H2S in-situ, using amine sweetening and Claus sulfur recovery units. NK & Jurassic fields are logistically farthest from KNPC facilities. The gases evolved from separators at the gathering centers (GCs) are handled depending upon their operating pressure and molecular weight. These gases become progressively richer as the pressure drops (HP gas at about 260-270 PSIG is leanest, LP gas at about 50-65 PSIG is richer and Tank Vapor at about 4" water column is richest in heavier fractions / value added components). In most locations, the tank vapor is compressed in condensate recovery units (CRUs) to a pressure sufficient to recover the bulk heaviers (condensate); at a few locations, it is compressed in vapor compressors to a pressure sufficient to export it alongwith LP rich gases. The LP & HP rich gases are then sent to the booster stations for compression & dehydration and onward export to KNPC's gas handling plants. The hot desert climate, especially during summers, does not favor gas dehydration down to 7 lb/MMSCF; in certain locations, a propane gas chilling plant reduces the feed gas temperature of the gas dehydration unit to about 45 °C. NK utilizes gas-lift as one of its artificial lift modes and comprises of a high-pressure lift gas grid and a significant fraction of its gas handling facilities is consumed by ‘recycle gas’. In principle, KOC bulk flaring, if any, is done at gathering centers. The condensate generated as a consequence of compression in the condensate recovery units is pumped to the LPG plant. S&EK & NK gases and condensate being similar, largely share inter-field gas transfer / handling facilities for the purpose of operational flexibility and avoiding over-redundancy. West Kuwait (WK) gas and condensate being significantly sour, are handled separately altogether; sweetening and sulfur recovery are carried out at refinery end in KNPC's Acid Gas Removal Plants (AGRPs) and the sweetened gas and condensate then join the S&EK & NK gas and condensate streams to be collectively processed in KNPC's Gas Plant for extraction of C2, C3-C4 (LPG), C5+, etc.