Kuwait Oil Company

Conventional coring does not provide core samples that are characteristic of the original formation condition. Thus, pressurized coring is required to capture samples that represent the in-situ composition of gases and liquids; pressure, volume, and temperature (PVT) data of the fluids, and porosity, permeability, and wettability, which are critical to reservoir interpretation and development. A customized high-performance water-based mud (HPWBM) was used successfully where prior attempts with conventional water-based mud (WBM) had failed.

The key well challenges included wellbore instability with caving shale and depleted reservoir sands. Previous attempts to retrieve pressurized core using conventional WBM proved unsuccessful because of the early activation of the pressurized capture mechanism caused by an accumulation of wellbore and mud solids linked to insufficient hole stability. A HPWBM containing liquid additives was customized to minimize solids content while stabilizing the shales and to minimize the differential sticking potential in the depleted reservoir. The formulation was finalized, based on laboratory testing, to optimize the bridging and inhibition package for the formations drilled.

Drilling and logging were successfully completed with no incidents; the fluids parameters were maintained to effectively clean the hole while controlling equivalent circulating density (ECD) through minimizing solids in the mud. The combination of salinity and liquid additives used minimized the total solids of the mud while effectively stabilizing the wellbore, which helped to reduce the premature activation tendency of the catcher system of the pressurized coring tool.

Pressurized cores were successfully retrieved with in-situ conditions and analyzed on-site, maintaining a pressure equivalent to the pore pressure. The core samples were retained in their native state for future studies. There was no nonproductive time (NPT) related to wellbore instability, and differential sticking was avoided by the customized bridging across the depleted reservoir. The successful collection of data enabled improved reservoir modeling.

This paper discusses the design of the HPWBM system, along with its technical features and benefits, which helped to successfully complete the first global 12 ¼-in. pressurized coring application. The customized HPWBM provided good shale inhibition, low solids and excellent lubricity, and eliminated the need for conventional shale stabilizing materials, which could have interfered with the capture of the pressurized core.

Oil and gas companies face major challenges for meeting increased energy demands around the world. There is a sharp decline in production from existing fields and at the same time, discovery of large new fields has become increasingly difficult. As a result, oil and gas operators around the world are implementing various strategies to find ways of increasing recovery from existing reservoirs With ultimate average recovery factor for oilfields on a worldwide basis of about 35%, companies are trying to improve recoveries through new technology initiatives such as integrated digital oil field approaches, which integrate reservoir and production system together for continuous monitoring of asset performance and production; optimization, and control of wells and fields. Comprehensive workflows and collaboration environments are key elements of any successful digital oil field operation. They integrate a multitude of data sources and applications, capture the knowledge of production processes, and enable improved decisions. These workflows help overcome the complexity of today's asset management operations. Kuwait Oil Company implemented such initiatives in one of its assets in Burgan oilfield which involved instrumentation at well site, a SCADA system for data acquisition and control, integrated asset management workflows together with state-of the art collaboration center enabling faster diagnostics for well and facility performance. The integration of surface and subsurface models in an automated workflow process allows quick review of well health and assists in planning for short-and long-term production optimization actions.

Carbon isotopic characterization of mud gas can add great value to the information collected at wellsite and nowadays the interest in this topic is increasing as documented by the study from Poirier et al. (IMOG 2017).

The presented study has the objective of illustrating the data logged through a cavity ring-down spectroscopic (CRDS) technique that allowed collection of robust and reliable carbon isotopic data at wellsite. The logged carbon isotopic data were then used for studying the behavior of two formations (Makhul and Najmah) across different fields. Makhul Formation represents the lower most Formation of Cretaceous in Kuwait, representing predominantly as carbonate rock. In lower Makhul, the high gamma radioactivity is due to enrichment of the shales by uranium. While, Najmah formation is an excellent source rock located in upper Jurassic, it consists of black calcareous limestone source rock with high organic content. Both formations are considered as major source rocks for petroleum systems in state of Kuwait. Many standard interpretation models from the literature were screened and adopted in inter-field correlation, resulting in a good matching with the geographical distribution of the fields.

The second part of the study will focus on the added value of recording carbon isotopic ratios up to C3. The analysis of δ13C3 is demanding from the instrumental point of view, thus, the benefits in terms of formation evaluation that comes from the logging of isotopes up to C3 will be illustrated in the study. With reference to other literatures, δ13C1 readings might be affected by mixing phenomena with biogenic gases, and thus they are not the best candidates to run maturity assessment through isotopes. Instead, carbon isotopic ratios of ethane and propane are not affected by mixing with biogenic gas, resulting in more robust and accurate interpretations. Few models from literature were applied on collected data, allowing choosing the one that matches best the behavior of the studied basin.

Independent measurements on the maturity of the source rock in the area confirmed that the trend highlighted through carbon isotopes logging at wellsite is correct, validating the usefulness of this technique at wellsite.

The increasing demand for hydrocarbon made it a challenge to maintain the oil production and maximize recoverable reserves in mature fields. Interconnected flowline surface network, of oil producing wells, varying in reservoir pressure, connected to a single processing facility, resulted in network bottlenecks and other flow assurance issues. This study objective is to predict the temperature changing effect on hydraulic flow behavior and optimize the most precise multiphase flow correlation for the selected fields.

The severity of bottlenecks can be profoundly affected by seasonal temperature changes, which require studying and pre-planning to reduce or avoid production losses. A flowline network model had been built and analyzed in-house using a commercial steady-state multiphase flow simulator for one of company's Gathering Centres (GC). GC-XY problematic, high pressure, headers were considered, which are receiving production from several fields in Kuwait. For representative results; comparisons were done for the prediction of multiphase flow correlations in horizontal and inclined pipelines.

The predictions of the Beggs & Brill (1975), the Baker & Gabb (1988), the Dukler et al. (1969), the Mukherjee and Brill (1983), and the Oliemans (1976) correlations and the Xiao (1990) mechanistic model were evaluated in this study. The comparison was limited to a temperature range from −5 to 55 Celsius degrees, light oil with API above or equal 30 degrees, and 6 inches flowline inner diameter. The study displays statistical error comparison between the predictions of each multiphase flow model used and suggests a correlation for the applied conditions in the selected field. Bottlenecks had been found in the network model, and a variety of solutions were proposed and simulated to overcome the bottleneck severity due to temperature changes. The results findings show a significate potential is reducing the bottlenecks severity up to 40 percent in the designed network and production enhancement of 18,000 barrels daily.

Detailed criteria and calculations were stated to compare and select the most accurate multiphase flow correlations for the chosen fields. Also, the project explains a procedure to model the suggested solutions and find the expected enhancement of production. Temperature overestimation can lead to severe bottlenecks, which require dedicated and reliable studies to minimize the losses due to heat transfer effect on oil viscosity and flow behavior.

One of the common challenging drilling environments is harsh rocks which require specially tailored drill bit design features to deliver the maximum drilling efficiency. The interbedded nature of harsh rock formations in combination with high rock strength results in reduced bit aggressivity and premature bit wear which increases the drilling costs. This paper presents field testing a new drill bit technology that addresses those challenges. The bit was deployed and tested in a vertical application in an exploratory well in North of Kuwait and achieved the fastest penetration rate in the application.

Numerous full scale pressurized laboratory tests were conducted on different rocks including limestone, sandstone and shale to develop and validate a new altered cutter geometry designed for carbonate applications. The main target of the simulations was optimizing the cutting action of the PDC cutter while drilling a carbonate formation. This resulted in development of altered cutter geometry designed for fracturing and shearing, offering improved effectiveness in medium to hard formations such as carbonates and clastic rock and more efficient cutting action than conventional round cutters. By creating subsurface cracks that propagate to the rock surface, the new cutter allows creation of thin and uncondensed cuttings, making an efficient use of energy.

The first 12¼ in. 6 blades 16mm configuration bit equipped with the new cutter geometry in conjunction with a stiff rotary BHA was tested in a vertical exploratory well in Bahrah Field, North of Kuwait. The bit delivered improved performance by completing a total interval of 2,655 ft from 5,915 ft to 8,570 ft in 60 hrs resulting in 44.2 ft/hr rate of penetration while drilling from Mutriba to Burgan formations. The bit demonstrated excellent durability with a dull grade of 1-1-WT-A-X-I-NO-TD after drilling in a highly interbedded harsh application where the lithology consists mainly of limestone, shale & sandstone.

The performance capability was further confirmed when the same bit drilled the second well to section TD completing a total interval of 2,630 ft with ROP of 68.7 ft/hr. achieving the top record run in north Kuwait vertical application in Bahrah field.

The 12¼ in. bit with the non-planar cutters surpassed the average rate of penetration (ROP) for the same application in Bahrah Field by 76% saving the operator significant drilling time and making this bit design the top performing drill bit in the field. As a result of the continuous research and field testing, the new cutter technology has drilled more than 10 million feet globally proving its success and efficiency in a wide range of applications.

Residual Oil Zones (ROZs) are an area of incrasing attention from hydrocarbon E&P industry with ever depleting reserves in known oil accumulations and advent of Carbon Dioxide (CO₂) Capture and Storage needs and technology. ROZ can serve as viable solution to both the future problems as a possible vast new oil resource and a prospect for reducing carbon emission. ROZs can be defined as thick pile of low-quality reservoir rock below traditional oil-water contact with about residual oil saturations of mainly irreducible oil resulting from the natural flushing of reservoir due to buoying forces and aquifer action in geological past in earlier oil-filled part of reservoir. The production of oil from ROZs from such reservoirs is technically and economicaly feasible through application of enhanced oil recovery techniques - largely through missible CO₂ flooding/injection in the zone because of the nature of fluid and reservoir rock. The depostional and tectonic regime in the Kuwait Petroliferous Basins is investigated to demonstrate the occurrence of and independently assess ROZ potential. The understanding of Kuwait Petroliferous Basin indicates that ROZs might be developed by hydrodynamic actions associated with tectonic regime. The degradation of oil by water action and related increase of sulfur content of crude oil can be used as workable proxy for identification ROZ potential of the rerservoir. The regional mapping, understanding of tectionic history and regional systhesis of crude oil composition shows an extensive stratigraphic and lateral existence of ROZ potential across the Kuwait Petroliferous Basin.

This study aims to provide strategic roadmap and detail data acquisition program that will reveal ROZ production potential in Kuwait for Kuwait Oil Company (KOC).

Typically, conventional cores provide indeterminate reservoir condition; suffer loss of unknown volume of hydrocarbon fluid and mechanical integrity while being retrieved. Most laboratory analysis thereafter are simulated however it's not truly turning back the lost conditions into in-situ condition. A fully captured, and pressure retained core is thought to be a solution to provide a true micro-reservoir at surface which explains the reservoir behaviour as it behaves in subsurface. This led to successfully deploying the technology to fully capture a large diameter pressured core for the first time in conventional hydrocarbon industry in Giant Burgan Field in southeast of Kuwait in a Middle Cretaceous Clastic reservoir and also to derive a number of critical parameters from the retrieved micro-reservoir. The technology involves lowering of a large diameter pressure corer (LPC) with an outer pressure vessel and inner core barrel. After the core is cut, a drop ball mechanism sets the inward movement of the inner barrel past a spring activated pressure seal thereby keeping the core in reservoir condition. While continuous pressure recording on the retrieved core, a core analyser (PCAL) system captures multiple sets of reservoir data through a predetermined slow depressurization without hampering any operations on the rig floor. Other than measuring accurate reservoir pressure, the analytical process provided for sampling of released gases, fluids and PVT samples in addition to in-situ bubble point estimation, all at the rig site. The onsite gas analysis with compositional changes during depressurization and bubble point estimation well matched with the subsequent analysis performed on the samples in laboratory. Thus, a real representative Upper Burgan reservoir sand was retrieved containing present reservoir pressure with all fluids retained. Additionally, it provided a nearly undisturbed core with high degree of original mechanical integrity. The final depressurized core is then sent for further laboratory investigations and geological studies including slabbing and plugging. This encapsulated "micro-reservoir" is less sensitive to unexpected events like delays during retrieval and analysis, avoiding damages of the core or loss of fluids. The technology stands out against systems delivering cores at partial or no pressure retention, as it retrieves cores at formation pressure with all fluids retained and core integrity unaltered.

The cement bond evaluation of wells completed with fiberglass casings has always been a challenge due to the very large difference in the acoustic behavior of fiberglass with respect to steel. This problem was faced in Kuwait when ultrasonic image logs were recorded for some wells completed with fiberglass casings that gave highly erratic readings and posed significant challenges with interpretation when applying the conventional methods. It was critical to field development engineers to have the precise status of the cement bond around fiber casings to ensure integrity of casing from encroachment of formation fluids in the zone of interest. This, in turn, required that cement bond logs do accurately and precisely evaluate the cement integrity. The logging company along with drilling engineers resolved the challenge of interpretation innovatively by an integrated approach of ultrasonic and sonic data. The approach used a recently introduced platform to develop a new concept of data processing in which high-accuracy interpretation of the cement bond behind fiberglass was made possible.

As has been observed through field and laboratory experiments, the conventional ultrasonic technique applicable to carbon steel pipes has been proven to be invalid in fiberglass tubulars because the velocity and acoustic impedance of fiberglass are much lower than steel; therefore, there is no resonance in fiberglass. A new method and interpretation tool was developed and applied to raw data to build on parameters specific to the fiberglass samples used in Kuwait through surface tests to identify the acoustic properties of fiberglass: acoustic impedance, attenuation factor, and velocity.

Standardized processing parameters were established for consistency and accuracy to determine the actual pipe thickness, radius and cement acoustic impedance from ultrasonic measurements in many wells. The resulting logs from the new method were found to be satisfactory by field development and they were then applied to earlier drilled wells to validate the results. The advanced platform used for data processing and integration has provided a reference interpretation prototype of log response in fiberglass casings in different scenarios to accurately determine whether cement bond is poor, good, or non-existing. A further investigation of ultrasonic late waveform arrivals could elaborate unique information on casing standoff and centration inside the wellbore. A reasonable casing integrity evaluation was also feasible from the new method resulting in good estimate of valid pipe thickness and acoustic impedance.

This paper illustrates the application and evolution of the new method, which enables advanced data processing and integration to provide robust images even beyond cement and pipe integrity. It has been implemented in many wells, and it has provided a significant improvement in quality of logging results in fiberglass casing wells. The new interpretation model can be successfully adopted wherever there is similar material used for casings.

Resistivity image logs are high-resolution tools that can help to unravel the depositional and structural organisation in a wellbore. They provide a particularly powerful dataset when calibrated against core, maximising their benefit for reservoir characterisation. This paper shows examples how very detailed image assessment from selected wells in the Greater Burgan Field has helped to constrain the stratigraphic model and depositional interpretations of the Cretaceous Burgan and Wara reservoirs.

A multidisciplinary study of 123 cored wells, integrating core sedimentology, petrography, bio- and chemostratigraphy, wireline well and resistivity image logs, has delivered a robust stratigraphic and depositional framework for one of the most important reservoirs in the world's largest siliciclastic oil field. A descriptive image facies scheme that has been calibrated against core and conventional well logs captures the lithological variation, sedimentary features and surfaces of the reservoir, providing a detailed proxy for the sedimentological evaluation of uncored intervals and wells.

The sand-rich lower Burgan (4S) comprises fine to very coarse-grained fluvial channel sandbodies that are locally separated by laterally restricted mudrock baffles. Image and core analyses suggest that the majority of the sandstones are high-angle cross-stratified and form stacked barforms within amalgamated channel sandbodies. Their consistent orientation towards the NE-E supports a low-sinuosity (braided) fluvial system resulting in a relatively simple, sheet-like depositional architecture across the field. Although slightly finer grained, the cored middle Burgan channel sandbodies (3SM) are similar to those in the lower Burgan. However, palaeoflow data from the imaged wells show a higher directional spread in the order of c.60-90° with a dominantly N to E orientation of the sandy barforms. Careful analysis of the orientation of the bounding surfaces between the sandstone packages indicates nearly equal proportions of obliquely and roughly parallel dip orientations in some wells. This suggests the formation of at least some lateral (point) bars and possibly the presence of higher sinuosity channels implying that sandbody architecture and fluid flow pathways could be more complex in the middle Burgan relative to the lower Burgan.

The examples from the Burgan and Wara Formations highlight the value of integrated image analysis for reservoir characterisation by delivering a consistent descriptive framework, embedding different datasets.