|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Saleh, Khaled (Kuwait Oil Company) | Al-Khudari, Abdulaziz Bader (Kuwait Oil Company) | Al-Najdi, Amer (Kuwait Oil Company) | Al-Azmi, Mejbel Saad (Kuwait Oil Company) | Al-Otaibi, Fahad Barrak (Kuwait Oil Company) | Joshi, Girija Kumar (Kuwait Oil Company) | Abdulkarim, Anar (Halliburton) | Farhi, Nadir (Halliburton) | Nouh, Walid (Halliburton) | Clarion, Benjamin (Halliburton)
Abstract Traditionally, 12.25-in. hole sections in the Jurassic formations were planned to be drilled with mud weight (MW) of 20 ppg and solids content of 45%. The planned drilling would use a rotary assembly from the Hith formation, crossing several zones in which mud losses or gains were likely. The casing would then be set in the thin shale base of the Gotnia formation. A minor inaccuracy in casing setting depth could often lead to well-control issues. Pore pressure drops severely below the shale base and requires a MW of 15 ppg. Passing this shale base can lead to severe losses and potential abandonment of the well. An anhydrite marker is located approximately 50 ft above the shale base. To reduce risk, the operator would normally drill to this marker at a rate of penetration (ROP) of 20-30 ft/hr, then decrease the ROP to 2 ft/hr. While slowly drilling the last part of the section, penetration would be stopped every few feet to circulate bottoms-up to receive samples confirming the shale base; this process requires an additional 24 hours of rig time. After reaching the casing point, the operator would pull out of the hole to pick up logging-while-drilling (LWD) tools to perform a wiping run. This logging, however, is frequently cancelled because of wellbore stability issues, resulting in the loss of important formation-evaluation data across this interval. A new solution has been developed, comprising drilling with a rotary assembly to the final anhydrite marker, then pulling the string out of hole to pick up LWD triple-combo and sonic tools, with a conventional gamma ray sensor placed only 6 ft from the bit. The remaining part of the section would then be drilled at 7-10 ft/hr until the gamma-ray tool detected the shale base, thereby determining the casing depth. In addition, it was planned to re-log the previously drilled interval. This solution prevented the well from potential abandonment and reduced drilling time. It also secured critical formation evaluation data for exploration and future field development. The engineered drilling solution was tried for the first time in these formation sequences within a harsh drilling and logging environment. The option of rotary steerable services with an at-bit GR sensor was not considered because of the high cost.
Abstract Formation evaluation challenges in highly fractured, stacked reservoirs with multiple source rocks and structural complexities which have complicated charging histories, are common in the Middle East. Finding additional pay zones, understanding the contribution of individual oils to the overall production, or evaluating the compartmentalization within the reservoir by resolving the heterogeneity of the reservoir rocks, are to name but a few. This work tries to understand the challenges posed by the sub-surface complexities and attempts to find answers through physical evidence; utilizing both onsite data acquired during drilling and data gathered through organic and inorganic laboratory measurements. Formation evaluation challenges are mostly attributed to formation heterogeneity, which we have aimed to address through the integration of petrophysical and geochemical data within this work. Therefore, a secondary aim of the present paper is to illustrate how such an integrated workflow can bring undiscussed value in terms of improved reservoir management and geological understanding of the field. This project encompasses the integration of petrophysical and geochemical analyses of the reservoir rocks. Geochemical data have provided the ability to make maturity, richness and other character interpretations and will be combined with important petrophysical properties of the carbonate intervals to predict reservoir heterogeneities. These interpretations could support perforation interval selection on subsequent wells in the field through the understanding of the mobility of the oils, and ultimately impact on production strategies. Best practices for thermally extracting hydrocarbons from drill cuttings, quality controlling advanced mud gas data and interpretive processes, together with the entire workflow followed, will also be elaborated. The analysis has the objectives of establishing results to support completion decisions through understanding reservoir quality and reservoir fluid heterogeneities specific to the basin studied and the petroleum system in place. The petrophysical reservoir properties such as hydrocarbons in-place, mobility of the oils, porosity, permeability, fracture intensity, geomechanical properties (brittle vs. ductile) and fluid quality assessment in the reservoir will be tied in to geochemical analyses to this extent. The reservoir properties determination pursued in this study has been carried out using a number of integrated analytical techniques on DST oil samples of six offset wells and rock cuttings, as well as petrophysical logs and advanced mud gas data. The concepts, tools and methods that have been demonstrated for evaluating crude oils, natural gases and petrophysical characteristics of the rocks are applicable to many problems in petroleum production and field development, as well as exploration efforts, and are largely recognized to help reducing the associated uncertainties in a cost-effective manner.
Abstract During well planning, drillers and petrophysicists have different principle objectives. The petrophysicist’s aim is to acquire critical well data, but this can lead to increased operational risk. The driller is focused on optimizing the well design, which can result in compromised data quality. In extreme cases, the impact of well design on petrophysical data can lead to erroneous post-well results that impact the entire value-chain assessment and decision making toward field development. In this paper, we present a case study from a syn-rift, Upper Jurassic reservoir in the Norwegian Sea where well design significantly impacted reservoir characterization. Three wells (exploration, appraisal, and geopilot) are compared in order to demonstrate the impact of overbalanced drilling on well data from both logs and core. Implications for reservoir quality assessment, volume estimates, and the errors introduced into both a static geomodel and dynamic reservoir simulation are discussed. This case study highlights the importance of optimizing well design for petrophysical data collection and demonstrates the potential for value creation. Extensive data collection was initially carried out in both exploration and appraisal wells, including full sets of logging while drilling (LWD), wireline logging, fluid sampling, and extensive coring. Both wells were drilled with considerable overbalanced mud weights due to the risk of overpressured reservoirs in the region. The log data was subsequently corrected for significant mud-filtration invasion, with calibration to core measurements guiding the interpretation. Geological and reservoir models were built based on results from the two wells, and development wells were planned accordingly. A thorough investigation of core material raised suspicion that there could also be a significant adverse effect of core properties resulting from overbalanced drilling. The implications were so significant for the reservoir volume that a strategic decision was made to drill a geopilot well close to the initial exploration well, prior to field development drilling. The well was drilled six years after the initial exploration phase with considerably lower overbalance. Extensive well data, including one core, were acquired. The recovered core was crucial in order to compare the reservoir properties for comparable facies between all three wells. The results from the core demonstrate distinctly different rock quality characteristics, especially at the high end of the reservoir quality spectrum. Results of the core study confirmed the initial hypothesis that overbalanced drilling had significantly impacted the properties of the core as well as the well logs. The study concluded that the updated reservoir model properties would significantly increase the in-place volumes compared to the pre-geopilot estimate. This study shows how well design adversely affected petrophysical measurements and how errors in these data compromised geological and reservoir models, leading to a suboptimal field development plan that eroded significant value. This example provides a case study that can be used to improve the well design so that petrophysicists and drillers can both be part of the same value creation result. Future work will include further laboratory investigations on the effects of high overbalanced drilling on core and possible “root causes” for compromised core integrity.
Abstract It is well known that the NMR relaxation time T2 is proportional to the molecular mobility of water or hydrocarbons in rocks. In unconventional tight rocks, water and hydrocarbons are trapped in small pores of nanometer sizes, and their molecular mobility is severely restricted, causing the NMR T2 to be much shorter than that of conventional cases where pore sizes are in micrometer ranges. There are demands for advanced NMR techniques to study those solid-like bound hydrocarbons. In the meantime, it is of great interest for petrophysicists and geochemists to understand kerogen models in order to determine thermal maturity and hydrocarbon potential of organic-rich source rocks, and always attractive to have practical techniques that are nondestructive and less time consuming. In this study, a series of NMR 1D and 2D experiments have been performed on various types of source rocks with emphasis on short NMR T2 components, from sub-milliseconds down to a few microseconds, which are associated with kerogen, heavy hydrocarbons, and small hydrocarbon molecules bound in nanopores. The results show that the NMR CPMG pulse sequence used for the T2 data acquisition is (1) not capable of detecting and measuring the very rigid solid component of the T2 shorter than 30 microseconds, which is thought from kerogen, and (2) uncertain for the NMR components with T2 between 30 microseconds and 0.1 ms, which is dependent on the inter-echo spacing time (TE). Instead, the solid echo-pulse sequence was used to acquire the early time NMR signals that represent rigid solid matters, such as kerogen, in rock samples that have short relaxation times of less than 20 microseconds. The NMR solid echo signals were fitted into a composition of a Gaussian plus exponential functions to better describe NMR responses of source rocks with the shortest relaxation time of a few microseconds. The Gaussian component in the NMR signal is the measure of rigid solids associated with kerogen in the source rock. Model rock samples of thermally immature outcrops of the Upper Jurassic Kimmeridge Clay Formation in the UK and the Green River Shale Formation in the USA were used for comparison studies between the low field solid NMR techniques and geochemical analytical methods. The thermal maturities of the samples were artificially altered through the hydrous pyrolysis method at selected temperatures. The comparison results show that the amplitude of the Gaussian component measurement by NMR strongly correlated with the S2 of pyrolysis. The NMR relaxation times of the solid portion are directly proportional to the thermal maturity determined by organic petrography. This study concludes that the nondestructive solid NMR method provides an alternative and rapid way to study solid organic matters. The combined techniques enable us to further study kerogen models and hydrocarbon-generating potentials in organic-rich source rocks.
Summary Ultra‐high‐pressure high‐temperature (uHPHT) reservoirs undergo extreme pressure depletion during their production life cycle. This results in significant reservoir compaction and consequent overburden subsidence with major consequences for wellbore mechanical integrity, safety, and field economics. However, the use of underdetermined geomechanical models to accurately predict compaction‐induced stress/strain changes on wellbores and its consequences during production time results in significant residual uncertainty. One method of measuring compaction‐induced stress/strain changes in wellbore is by the emplacement and measurement of radioactive markers. Although it is long established in normal pressure reservoirs, it is rare in uHPHT projects. The Culzean uHPHT gas‐condensate field is located in the UK Central North Sea. To constrain geomechanical model compaction uncertainty, radioactive markers were deployed. The objective was to accurately acquire preproduction baseline measurements and subsequent changes through periodic measurements during production life. These accurate wellbore measurements would then be compared with the geomechanical model to help calibrate predicted to actual compaction. By doing so, the objective is to enable better informed decisions regarding well and field management. The Culzean uHPHT radioactive marker project comprised a planning phase and a preproduction safe deployment including a baseline survey phase. Subsequent repeat measurements are planned during field production life. The emplacement and surveying of the subsurface radioactive markers for compaction monitoring in uHPHT reservoirs is a high value but nontrivial operation. In addition, much knowledge and experience of the methodology has been lost. This paper contributes to published literature by describing the successful emplacement and monitoring of subsurface radioactive markers on Culzean and aims to capture learnings and knowledge for future workers. Early detailed planning coupled with extensive testing is key to successful deployment. Timely engagement of all stakeholders and ensuring all decisions are aligned with safety and environmental considerations also contribute to realization of the project aims.
Summary The effects of temperature on the permeability coefficients of carbonaceous shales and the underlying mechanisms have been investigated experimentally. Pressure-pulse-decay gas-permeability tests were performed on seven shale plugs with different lithological compositions, organic-matter contents ranging from 0.8 to 11.7% total organic carbon (TOC) and thermal maturity between 0.53 and 1.45% random vitrinite reflectance (VRr). During the tests, the measuring temperatures were changed stepwise from 30 to 120°C and back to 30°C while axial load and confining pressure were kept constant. Sister plugs were used for mechanical tests to investigate the creep response upon thermal loading under the same temperature conditions. The samples showed varying degrees of permeability reduction by up to 71% with increasing temperature. This reduced permeability persisted during the cooling phase. The observed permeability changes reflect the elastoplastic deformation upon the thermal compaction of the rocks. Permeability reduction and creep response with increasing temperature are evidently controlled by organic matter, although clay minerals also played an important role. Organic-matter- and clay-rich shales exhibit the strongest response to temperature, while temperature effects were slightly smaller for overmature samples. Rock mechanical analysis showed that permeability reduction correlates with temperature-related creep/deformation of the shales. Given the strong temperature dependence of the mechanical stiffness of solid organic matter and of the viscosity of bituminous solids/liquids, more attention should be paid to temperature effects in the assessment of shale permeability. Our experimental results document that thermal stimulation has negative effects on shale-transport properties and that measurements conducted at laboratory temperatures can lead to substantial overestimation of in-situ shale permeability.
Abstract Given the increased demands on the production of hydrocarbons and cost-effectiveness for the Operator's development wells, the industry is challenged to continually explore new technology and methodology to improve drilling performance and operational efficiency. In this paper, two recent case histories showcase the technology, drilling engineering, and real-time optimization that resulted in record drilling times. The wells are located on shallow water in the Gulf of Mexico, with numerous drilling challenges, which typically resulted in significant Non-Productive Time (NPT). Through close collaboration with the Operator, early planning with a clear understanding of offset wells challenges, well plan that minimize drilling in the Upper Cretaceous "Brecha" Formation were formulated. The well plan was also designed to reduce the risk of stuck pipe while meeting the requirements to penetrate the geological targets laterally to increase the area of contact in the reservoir section. This project encapsulates the successful application of the latest Push-the-Bit Rotary Steerable System (RSS) with borehole enlargement technology through a proven drilling engineering process to optimize the drilling bottomhole assembly, bit selection, drilling parameters, and real-time monitoring & optimization The records drilling times in the two case histories can be replicated and further improved. A list of lessons learned and recommendations for the future wells are discussed. These include the well trajectory planning, directional drilling BHA optimization, directional control plan, drilling parameters to optimize hole cleaning, and downhole shocks & vibrations management during drilling and underreaming operation to increase the drilling performance ultimately. Also, it includes a proposed drilling blueprint to continually push the limit of incremental drilling performance through the use of RSS with hydraulics drilling reamers through the Jurassic-age formations in shallow waters, Gulf of Mexico.
Edappillikulangara Chinnappan, Reji (Kuwait Oil Company) | Telang, Milan (Kuwait Oil Company) | Quttainah, Riyad (Kuwait Oil Company) | Radhakrishnan, Gokulnath (Maxtube Limited) | Fernandes, Alwyn (Maxtube Limited) | Rajendran, Kailas (Maxtube Limited)
Abstract Asphaltene deposition in production tubing is a major flow assurance challenge. Common strategies to mitigate Asphaltene deposition downhole include mechanical or solvent cleanouts and chemical inhibition. These are associated with production deferment, high job costs, HSE risks and operational issues. In a worldwide first, Kuwait Oil Company (KOC) has addressed this challenge using Fiberglass (GRE) Lined Production Tubing. This technology was implemented in two trial wells. This paper chronicles the different mitigation strategies employed by KOC and presents the findings of the above-mentioned successful trials. Tendency of scale to stick on smoother, non-metallic surfaces, is known to be less than on bare steel surface. KOC had trialed internal coating to mitigate Asphaltene deposition in tubing, but the experience was not satisfactory. KOC has been successfully using GRE lined tubing for corrosion protection and scale prevention in oil and water wells. Considering GRE's smoother surface, lower zeta energy and thermal insulation, it was decided to conduct a trial of GRE lined tubing in wells with Asphaltene deposition problems. Frequency of cleanout and Well Head Pressure (WHP) trends, before and after installation of GRE Lined Tubing, were compared for evaluation. The paper chronicles the trial results and provides a comparison of implementation costs against currently employed tubing cleanouts by Coiled Tubing (CT) using a Diesel-Toluene mixture. Two wells, requiring frequent tubing cleanout of Asphaltene, were selected as candidates. Trends over a period of 13-15 months after installation of GRE lined tubing showed up to 74 % reduction in WHP decline rate compared to pre-installation periods. Cleanouts were avoided against an earlier frequency of 3 to 3.5 jobs per year. This resulted in following benefits: (1) Direct annual operational savings of 519,750 US $ per well (2) Additional production by increased uptime of 1 to 1 ½ months (3) Avoidance of Coiled Tubing sticking, occurring in similar wells, and the resultant workover cost (4) Eliminating production deferment due to this workover (5) An environment friendly and safe methodology not requiring handling of toxic, highly flammable Toluene, used for the clean outs. Comparison of the economics show clear-cut benefits of GRE lined tubing over tubing cleanouts. In view of the applicability in most of their high API gravity Jurassic oil wells, KOC has decided on wide scale implementation of this technology. As this is the first known case of its kind worldwide, we expect that this paper will be highly beneficial to operators faced with challenges in producing Asphalteinic oil and those engaged in CO2 EOR campaigns. Besides sharing experience, the authors aim to generate global operator engagement to optimize this new solution, possibly combined with other solutions, to tackle Asphaltene deposition as efficiently as possible.
Soroush, Mohammad (University of Alberta and RGL Reservoir Management Inc.) | Roostaei, Morteza (RGL Reservoir Management Inc.) | Hosseini, Seyed Abolhassan (University of Alberta and RGL Reservoir Management Inc.) | Mohammadtabar, Mohammad (University of Alberta and RGL Reservoir Management Inc.) | Pourafshary, Peyman (Nazarbayev University) | Mahmoudi, Mahdi (RGL Reservoir Management Inc.) | Ghalambor, Ali (Oil Center Research International) | Fattahpour, Vahidoddin (RGL Reservoir Management Inc.)
Summary Kazakhstan owns one of the largest global oil reserves (approximately 3%). This paper aims at investigating the challenges and potentials for production from weakly consolidated and unconsolidated oil sandstone reserves in Kazakhstan. We used the published information in the literature, especially those including comparative studies between Kazakhstan and North America. Weakly consolidated and unconsolidated oil reserves in Kazakhstan were studied in terms of the depth, pay‐zone thickness, viscosity, particle‐size distribution (PSD), clay content, porosity, permeability, gas cap, bottomwater, mineralogy, solution gas, oil saturation, and homogeneity of the pay zone. The previous and current experiences in developing these reserves were outlined. The stress condition was also discussed. Furthermore, the geological condition, including the existing structures, layers, and formations, were addressed for different reserves. Weakly consolidated heavy‐oil reserves in shallow depths (less than 500‐m true vertical depth) with oil viscosity of approximately 500 cp and thin pay zones (less than 10 m) have been successfully produced using cold methods; however, thicker zones could be produced using thermal options. Sand management is the main challenge in cold operations, while sand control is the main challenge in thermal operations. Tectonic history is more critical compared with the similar cases in North America. The complicated tectonic history necessitates geomechanical models to strategize the sand control, especially in cased and perforated completions. These models are usually avoided in North America because of the less‐problematic conditions. Further investigation has shown that inflow‐control devices (ICDs) could be used to limit the water breakthrough, because water coning is a common problem that begins and intensifies the sanding. This paper provides a review on challenges and potentials for sand control and sand management in heavy‐oil reserves of Kazakhstan, which could be used as a guideline for service companies and operators. This paper could be also used as an initial step for further investigations regarding the sand control and sand management in Kazakhstan.
Abstract Geothermal District Heating (GDH) doublets in the Central part of the Paris Basin, particularly in the Capital City suburban areas, face two major concerns: The replacement of aging and declining, when not damaged, well infrastructures and productive/injective capacities; GDH doublets density, approaching overpopulation in some areas, which limits well replacement opportunities and clouds new development issues bearing in mind the space limitations in urban areas and the thermal breakthrough/reservoir cooling shortcomings. The Paris suburban Cachan site was considered a relevant candidate for a first implementation of an alternative well architecture design. In March 2018, the second sub-horizontal geothermal injection well, GCAH2, was successfully tested at the Paris suburban Cachan site, thus validating this innovative sub-horizontal well (SHW) architecture, initiated on the previously drilled production well, GCAH1, recorded as a world first with 1000 m 8-1/2 in. open hole horizontal drain. The sub-horizontal drain sections of the wells were drilled using the geosteering technique in place of the usual geometric pre-planned trajectory. Geosteering was successfully used for optimal well placement of the geothermal injection/production doublet. The real-time data was correlated to reservoir model to design and implement a reliable well trajectory and to increase reservoir exposure. Alongside LWD (logging while drilling), advanced near real-time cuttings analysis utilizing elemental and mineralogical measurements and custom software was used to improve decision making while drilling. The integration of chemo-stratigraphy, mud logging, wireline, logging while drilling and production test results improved the correlation between wells, supporting the building of a proper geological model and reservoir characterization.