Nagarkoti, Malvika (Baker Hughes, a GE company) | Pooniwala, Shahvir (Baker Hughes, a GE company) | Alam, Anwar (Baker Hughes, a GE company) | Anthony, Elred (Kuwait Oil Company) | Al-Othman, Mohammad (Kuwait Oil Company) | Aloun, Samir (Kuwait Oil Company) | Buhamad, Ali (Kuwait Oil Company) | Ashkanani, Meshari (Kuwait Oil Company)
Proppant fracturing treatments in sandstone formations are routinely executed in Kuwait, however when carbonate formations are the target, acid fracturing is the preferred treatment method. It has been observed that acid fracturing delivers a high initial production however maintaining a sustainable production rate is a challenge in the tight cretaceous carbonate formations in Kuwait. A production enhancement technique needed to be identified in order to deliver more sustainable production and maximize recovery from these carbonate formations.
Based on global experience it was proposed that proppant fracturing can deliver more sustainable production rate as compared to acid fracturing.
Proppant fracturing had been previously attempted on two occasions in Kuwait, however both the attempts were evaluated as not being operationally successful. Hence prior to executing the first successful proppant fracturing treatment in carbonates in Kuwait a thorough study was undertaken to identify and mitigate the possible risks.
The cretaceous carbonate formations in North Kuwait are relatively shallow and are known to be tight and highly ductile. Due to the ductility of these formations, proppant placement and reduction of the fracture conductivity due proppant embedment were thought to be significant risks. During the course of the project, detailed core analysis and testing was conducted using formation core samples to ascertain the severity of this risk.
Successful execution of this hydraulic fracturing treatment was pivotal in order to plan the future production strategies from these formations. A cautious approach needed to be followed as proppant placement was of paramount importance. Different strategies were incorporated in the fracturing workflow to ensure the success of the treatment and to maximize data collection in order to optimize future treatments and well placement. Multiple mini-fracs, temperature logs and pumping of novel non-radioactive tracer proppant were some of the techniques utilized.
During execution various decisions were taken real-time to ensure success of the treatment. It was observed that all parameters were consistent with the results of the core and laboratory testing conducted during the initial phase of the project which lead to optimizing the proppant placement.
The success of this treatment has been a game changer resulting in more wells being identified as candidates for proppant fracturing in this field.
Now that proppant placement has been established the objective of future treatments is to optimize fracture designs, fluids and treatment schedules which will help the future production enhancement strategy for this field.
Lessons learnt from this first successful well will be applied to future wells planned in carbonate reservoirs in Kuwait, in order to maximize recovery.
Toempromraj, Wararit (PTTEP) | Sangvaree, Thakerngchai (PTTEP) | Rattanarujikorn, Yudthanan (PTTEP) | Pahonpate, Chartchai (PTTEP) | Karantharath, Radhakrishnan (TGT Oilfield Services) | Aslanyan, Irina (TGT Oilfield Services) | Minakhmetova, Roza (TGT Oilfield Services) | Sungatullin, Lenar (TGT Oilfield Services)
Success towards waterflood optimization requires the accessibility of downhole contribution and injection, challenging on the conventional cased-hole multi-zone completion where contribution and injection are gathering through sliding sleeve. This paper will describe the success in defining flow profile behind tubing by utilizing Temperature and Spectral Noise Logging.
With response in frequency and noise power when fluid flowing through completion accessories, perforation tunnels and porous media, fluid entry points for producer and water departure point can be located by noise logging. Additionally, conventional temperature logging can usually define degree of intake and outflow along with change in fluid phase as a result of change in temperature. In combination of these implications, downhole flow contribution and injection profile can certainly be determined even though fluid moving in and out through production tubing and casing.
Regarding pilot field implemtation in Sirikit field, two multi-zone-completed candidates have been selected, operations were carried-out for producer and injector according to the programs individually designed including logging across perforation intervals and station stops for multi-rate flow, transient and shut-in periods. Longer well stabilization is necessary for injector. In addition to production/injection logging interpretation by incorporating pressure, temperature, density and spinner data, the temperature simulation model is generated to determine downhole flowing/injecting contribution with parameters acquired during logging, for example, pressure and temperature. The other reservoir and fluid properties, e.g. permeability, thickness, hydrocarbon saturation, skin, heat conductivity and capacity have been analog based on available data from neighboring areas. Therefore, the historical data on production and injection including nearby well performance may be crucial to define necessary input to the model. In association with the interpretation of noise logging which is utilized in locating contributing/injecting zones, the interpretation strongly relies on acquired temperature data and outputs of temperature simulation model to match with measured temperature profile. However, limitations have been documented when dealing with multi-phase flow, especially in low flow rate condition – considered 5 BPD as a threshold. Sensitivity run with associated paramenters in the interpretation can significantly reduce the number of uncertainties to match with measured temperature profile.
Temperature and Spectral Noise Logging to provide input to temperature model can definitely help accessing downhole injection profile for the injector by taking benefit of one phase injecting and having contrast between injecting fluid and geothermal temperatures. This application can significantly improve the waterflood performance and optimization particularly in high vertical heterogeneous reservoirs – thief zones can be identified and shut-off consequently. However, defining downhole contribution for low-rate oil wells producing from multi-layered depleted reservoirs especially in undersaturated condition is still a challenge.
Wehunt, C. Dean (Chevron North America Exploration and Production Company) | Lattimer, Stefan K. K. (Chevron Europe, Eurasia, and Middle East Exploration and Production Company) | McDuff, Darren R. (Chevron Energy Technology Company)
In this paper, we provide an update on recent advances for and summarize global experiences with dendritic-acidizing (DA) methods, or acid tunneling. We include both coiled-tubing (CT) deployed methods and non-CT methods, and discuss process limitations, candidate-selection criteria, job-design factors, operational learnings, risks, and surveillance requirements and opportunities. A comprehensive review of published information is provided for three different tunneling methods along with relevant information for several other tunneling methods. This literature information is supplemented by depth, temperature, and pressure records for the three processes, which are discussed in detail. Execution factors such as logistics required, length of time required, and volumes of acid and other fluids used are also compared for the three methods.
Previous papers have focused on only one of the methods, whereas we will discuss acid-job optimization, process risks, and surveillance requirements for multiple acid-tunneling methods in substantially greater depth than have past authors. The three methods detailed in this paper are all viable but may have different niches. Differences in the job counts for the different methods are easily explained by differences in process vintages, execution speeds, and depth limitations. Previous optimization efforts were focused on tunnel creation but not acid-job effectiveness in terms of the wormholes generated adjacent to the tunnels; however, some progress is now being made in that regard. There are differences in the processes regarding pushing or pulling the jetting nozzles into the tunnels, and differences in resulting tunnel trajectories. Prejob caliper data are more critical for one of the processes than for the others, and there are significant differences in ability to measure or control tunnel direction. The tunneling tools have different sizes, but when toolsize alternatives are available, the larger tool sizes offer no clear advantages to the operator. Useful risk-mitigation measures are also discussed, and a comprehensive bibliography is included to facilitate further examination of the technology alternatives by other petroleum-industry professionals.
Acid jetting is a well stimulation method for carbonate reservoirs, with observed positive production enhancement in some extended-reach horizontal wells. It is a process in which a reactive chemical solution is injected at a high rate at specific entry points via relatively smaller nozzles. The flow out of the nozzles is designed to be a fully turbulent jet which impinges on the porous surface of the rock, leading to a dissolution structure. That dissolution structure is of great interest as it determines the quality of the well stimulation job, which correlates directly to the well productivity. This work is the second step in the overall project about a comprehensive study of acid jetting as a successful stimulation method for carbonate formations. The first step was an experimental study performed using a linear core-flood setup including a jetting nozzle. The objective was to understand the mechanism of acid jetting on carbonate cores and identify the important parameters in the experimental outcome. The current study aims at describing acid jetting from a mathematical standpoint, while using experimental results as model validation and improvement tools. Previously published acid jetting laboratory experiments results revealed the recurring creation of a large dissolution structure at the impingement location in the shape of a cavity and, depending on injection conditions, the propagation of wormholes through the core.
A core-scale computational fluid dynamics model has been developed to simulate cavity and wormhole growth in acid jetting. It is a three-dimensional model which alternates between the two fundamental aspects of the overall acid jetting process. Firstly, it models the fluid mechanics of the turbulent jet exiting the nozzle and continuously impinging on the porous media transient surface. The jet fluid dynamics are implemented using a 3D transient finite volume numerical solver using Large Eddy Simulations (LES) with the Smagorinsky-Lilly sub-grid model to solve the Navier-Stokes and continuity equations. The results of this simulation include a velocity and pressure distribution at the porous media surface. Secondly, it models an irreversible chemical reaction with dissolution and transport at the impingement location between the fluid and the rock matrix. The reactive transport is modeled using the conventional kinetics of the dissolution of calcite by hydrochloric acid. This two-step model successfully replicates experimental results and observations for the cavity growth. It can then be coupled with a wormhole growth model to represent the entire experimental acid jetting outcome.
The modeling and computational tool for acid jetting developed in this paper will build the understanding for the upscaling and integrated dynamic modeling of an acid jetting stimulation job in the field. It will thus lead to the establishment of a standard for predicting and improving field applications of acid jetting.
The paper provides an update on recent advances for, and summarizes global experiences with, dendritic acidizing methods,
Previous papers have focused on only one of the methods, whereas the authors will discuss acid job optimization, process risks, and surveillance requirements for multiple acid tunneling methods in substantially greater depth than have past authors. The three methods detailed in the paper are all viable but may have different niches. Differences in the job counts for the different methods are easily explained by differences in process vintages, execution speeds, and depth limitations. Previous optimization efforts were focused on tunnel creation but not acid job effectiveness in terms of the wormholes generated adjacent to the tunnels; however, some progress is now being made in that regard. There are differences in the processes regarding pushing or pulling the jetting nozzles into the tunnels, and differences in resulting tunnel trajectories. Pre-job caliper data are more critical for one of the processes than for the others, and there are significant differences in ability to measure or control tunnel direction. The tunneling tools have different sizes, but when tool size alternatives are available, the larger tool sizes offer no clear advantages to the operator. Useful risk mitigation measures are also discussed in the paper. The paper includes a comprehensive bibliography to facilitate further examinations of the technology alternatives by other petroleum industry professionals.
Azim, Shaikh Abdul (Kuwait Oil Company) | Nugroho, Cahyo (Baker Hughes, a GE Company) | Sitinjak, Eri (Baker Hughes, a GE Company) | Al-Mutairi, Fayez (Kuwait Oil Company) | Al-Awadh, Ahmad (Kuwait Oil Company) | Boland, Ghadeer T (Kuwait Oil Company) | Mesri, Maryam M (Kuwait Oil Company)
This paper presents the first utilization of Logging While-Drilling Nuclear Magnetic Resonance (LWD NMR) and azimuthal resistivity inversion to characterize the Zubair reservoir in the North Kuwait. The Zubair formation is a complex sandstone reservoir. In general, in highly deviated wells, formation complexity causes polarization horns in the resistivity measurements. This effect is leading to both inaccurate resistivity values and related saturation calculations. Therefore, LWD NMR which is insensitive to polarization horns was used to accurately calculate saturation values. The accurate saturation calculation values in highly deviated well has been demonstrated in well-A. Subsequently, the NMR data were used to analyze the grain size distribution in the Zubair reservoir to be modelled and correlated to the lateral extension of the sand and shale bodies generated by azimuthal resistivity inversion.
The LWD NMR tool was deployed in the Dual Wait Time (DWT) mode enabling to differentiate between hydrocarbon and water. The reliability of the saturation profile was later on confirmed by the production testing run in Well-A. The LWD NMR saturation was compared with production testing from one layer of the Zubair formation. Grain size analysis from the LWD NMR was evaluated using the following parameters: T2 distribution, total and effective porosity, and saturation.
The LWD NMR saturation for Well-A was confirmed by the production test result. The initial production test from 1B_LCH layer in Zubair formation showed a 12% water cut, which after six months increased to 34%. The water increase was clearly observed from the LWD NMR saturation, which also showed two different saturation profiles in this 12-feet thick layer sand-body. However, this saturation differential was not clearly observed from the LWD propagation resistivity.
The production test confirmation from Well-A showed that the LWD NMR saturation profile was reliable and could be used in Well-A to validate potential low-resistivity pay zones.
Azimuthal resistivity inversion was performed by means of a newly developed algorithm which used the omni-directional and extra-deep LWD resistivity measurements of the Multi-Component-while-Drilling (MCWD) data. The algorithm is based on a 1D anisotropic layered model.
Based on LWD NMR saturation, Well-B was found to have three potential hydrocarbon-bearing intervals with low resistivity pay zones. These intervals had a gross thickness in the range from 15ft to 25ft. The inversion result in Well-B successfully showed the lateral continuity of the sand and shale layers. Some thin layers were seen clearly from the MCWD inversion but were not shown by the standard distance-to-bed boundary inversion algorithm.
Grain size analysis provides supporting geological evidence to help assess reservoir quality. LWD NMR saturation profile and grain size analysis, together with sand and shale lateral extension from azimuthal resistivity inversion, provide an integrated solution that can characterize a complex sandstone reservoir and improve the geological model.
Imtiaz, Saad (Baker Hughes, a GE company) | Perumalla, Satya (Baker Hughes, a GE company) | Hynes, Laura (Baker Hughes, a GE company) | Basu, Pramit (Baker Hughes, a GE company) | Shinde, Ashok (Baker Hughes, a GE company) | Benmamar, Salim (Baker Hughes, a GE company) | Chakrabarti, Prajit (Baker Hughes, a GE company) | Sherbeny, Wael El (Baker Hughes, a GE company)
In today’s challenging market conditions, the probability of successful well delivery can be increased and influenced by implementing fit-for-purpose pre-drill and real-time geomechanical solutions. These tailored geomechanical solutions add value to the project by delivering a cost-effective well, with reduced non-productive time (NPT), and a lower risk of health, safety, and environment (HSE) concerns. Geomechanics guided decision making, both in the pre-drill and in the real time phases, has a wide range of applications depending on the complexity present in the drilling environment, e.g., high-pressure, high-temperature (HPHT) regimes, reactive clays, depleted reservoirs, weak shales, highly stressed areas, etc.
This paper discusses the application of advanced geomechanics in three specific drilling environments (a) drilling a highly deviated well in a transitional fault regime, onshore the Nile Delta, (b) mitigating wellbore instability caused by reactive shales, in the Middle East and (c) drilling lateral wells in a highly-stressed carbonate formation. The paper also discusses how integrated pre-drill and real-time geomechanical solutions helped in achieving drilling success without adding major cost to the project.
In study (a) the operator had successfully drilled many vertical wells in the onshore field on the Nile Delta without significant problems, yet was having severe issues drilling deviated wells. A detailed pre-drill model revealed the possibility of a transitional faulting regime, in association with anisotropic rocks, drilled by a slick Bottom Hole Assembly (BHA), could be a major reason for this. Real-time geomechanics were deployed to validate the pre-drill understanding, along with mud additive recommendations and a slight modification to the drill string. In a different study (b) performed in another onshore Middle East field, there was a challenge to drill high-angle wells through troublesome shale formations, which resulted in various sidetracks and a significant amount of wellbore instability issues. These issues limited well configuration options for field development to near vertical wells. A pre-drill geomechanical study was carried out to understand the root cause of the failures that resulted in customized mud weight and mud type solutions for drilling higher angle wells. With these customized recommendations and later on a 3D Geomechanical model, horizontal wells have been drilled successfully for optimal draining of the reservoir resulting in breakthrough in field development plan. In study (c) there was significant wellbore instability challenges while drilling lateral wells through highly-stressed carbonate reservoir. A comprehensive study helped in understanding the geomechanical behavior. In example highlighted the drilling team was using lower than required mud weights in a horizontal well. The geomechanical model was adjusted considering time and space for specific case using the geomechanical understanding. The focused geomechanical modeling helped to adjust the mud weight. Suitable mud weight along with pseudo real-time monitoring helped in successful delivery of the horizontal well.
The three studies presented are onshore. Conventional wisdom for onshore drilling has a bias for low-cost solutions. However, the complexity of each drilling campaign was different. In all the cases the adoption of integrated geomechanics through the planning and operation phase ensured successful project completion with minimal non-productive time (NPT).
The combination of horizontal wells and multistage fracturing enabled the development of tight carbonate reservoirs. The successful completion of these reservoirs can be challenging. Correct placement of multistage intervals plays a critical role in improving and sustaining production. Openhole (OH) multistage (MS) technologies enhances reservoir contact and productivity by optimizing the distribution of the stages across the openhole. This paper presents an engineering technique to optimize OH fracture stages and cluster placement distribution within heterogeneous unconventional oil carbonate reservoirs based on formation, completion properties, and reservoir fluid distribution.
Completion technology is based on distributing intelligent packers along the lateral section to develop the MS fracturing stages. Intelligent packer displacement influences fracture effectiveness and conductivity. Equal spacing packer placement can undermine formation potential and productivity results. The placement of the packers and their ports is based on the petrophysical and mechanical properties of the formation to increase the cumulative production in a shorter timeframe and to help improve recovery. The method followed is based on an analysis of the reservoir properties (porosity and permeability). These were later integrated with the measured rock mechanical properties. The developed integrated model was used to categorize the rock into segments that share similar properties.
The use of an advanced azimuthal sonic tool with a high signal-to-noise ratio and wider frequency response helped to improve the accuracy in assessing formation mechanical properties. In addition, conventional logs, when combined with formation mobility measurements, help to calibrate the permeability model and classify the formation into distinctive clusters. These clusters are then grouped according to their mechanical and brittleness properties to form a separate unit with a selected fracture port to help ensure the necessary fracture length. The developed method provides an opportunity to determine the necessary fracture stages and to reduce the risks of overor underplacement. It also improves stage integrity, helps to ensure better distribution of the acid across the formation matrix, and provides effective propagation of the fracture network.
The applied procedure follows an innovative approach to optimize the fracture stage and cluster placement distribution across the reservoir using a new combination of advanced and conventional data acquisition and interpretation. The case study presented in this paper demonstrates the benefits of engineered fracturing stage placement, as compared to a geometric displacement.
Alattar, A. (Schlumberger) | Mustafa, M. M. (Schlumberger) | Nobre, D. (Schlumberger) | Applegate, R. (Schlumberger) | Pushkarev, M. (Schlumberger) | Dashti, S. (Schlumberger) | Saleh, K. (Kuwait Oil Company) | Saffar, A. Hussein (Kuwait Oil Company) | Harbi, A. Al (Kuwait Oil Company) | Anas, M. (Kuwait Oil Company)
The deployment of a new positive displacement motor (PDM) technology as a solution to improve drilling performance in deep vertical exploration wells in northern Kuwait. The new technology of the positive displacement motor was developed within the framework of new capabilities in motor optimization modeling, a holistic approach to configuring motor components as an integrated unit, and new engineering advances in the material and design of motor components. The engineering advances and innovations can be distinctly categorized into two major components, the power section and the lower end. The power section components went under extensive empirical and experience-based failure analysis to refine the design of the subcomponents. The refined designs were then scrutinized with the industry-first motor optimization modeling that simulates both the performance and fatigue of the power section by analyzing eight influential variables of down-hole conditions, and components material and geometry. The second component, is the newly designed high torque lower end which houses an overhauled assembly of transmission and bearing sections. The new lower end was engineered to reliably handle and fully harness the full capabilities of the power section. The result, is an integrated new motor technology that is characterized by its superior resistance to stall, ability to sustain higher limits of differential pressure, and performance reliability in harsh drilling environment.
Kuwait Oil Company (KOC), with its ever-expanding exploratory drilling campaign in northern Kuwait, was looking for significant improvements in drilling performance of vertical deep-drilling exploration wells. As such, KOC agreed to test the new motor technology in an exploration field north of Kuwait. The deployment of the new technology would take place in the 16 in section of a vertical well with a starting planned depth of 10,565 ft (3,220 m) and a total depth of 14,605 ft (4,456 m). The section drills through highly-interbedded and abrasive sandstone and carbonates strata with highly-variable windows of pore pressure and rock compressive strength. Given the complex lithology and the high-pressure environment, previous drilling campaign were tainted by low penetration rates, and motors and bits failures.
In March of 2017, the new motor technology was field tested for the first time worldwide in northern Kuwait. The field test run covered an interval of 3,658 ft (1,115 m) over three runs. The new motor technology justified its higher specifications by improving the rate of penetration (ROP) by 62% compared with the fastest offset well drilled. The superior rate of penetration can be attributed to the new motor ability to deliver higher ranges of differential pressure, specifically 57% higher than offset wells. The deployment of the new motor technology successfully proved the capabilities of the new motor in drilling optimization and reliability, and also validated the engineering and modeling processes behind the new components.
Jahdhami, Moosa Al (Petroleum Development Oman) | Maag, Jan Willem de (Shell Global Solutions International B. V.) | Mueller, Alexander (Shell Global Solutions International B. V.) | Narhari, Srinivasa Rao (Kuwait Oil Company) | Kolawole, Olusegun (Kuwait Oil Company) | Kidambi, Vijaya Kumar (Kuwait Oil Company) | Al-Qadeeri, Bashar (Kuwait Oil Company) | Dashti, Qasem (Kuwait Oil Company)
Seismic data in Raudhatain field in Kuwait is strongly contaminated with multiples that impair the image of reservoir reflectors and challenge the structural as well as the quantitative interpretation. A reliable reservoir interpretation depends on an optimal attenuation of multiples (free surface and interbed). In this project, we demonstrated that a significant amount of multiple energy was attenuated by implementing 3D SRME together with data and model driven interbed de-multiple using two strong shallow reflectors as the dominant multiple generators.
The project was run with a primary objective of a successful multiple attenuation at the Jurassic level. Initially, 3D Fourier interpolation was applied to regularize and infill shots and receiver independently, to prepare the data for 3D multiple attenuation. However, the survey in some areas was undershot due to agricultural activities, resulting in massive data gaps which presented challenges for data regularization/interpolation.
Since the 3D data interpolation results demonstrated that this approach was suboptimal and inadequate to infill all data gaps, especially the large ones, a new strategy of incorporating legacy data (from the same area), was followed to infill these gaps in a more appropriate way.
The 3D merged dataset (vintage and new data) was used as input for 5D interpolation software which regularizes and infills the data in 5D senses producing fully regular Common Offset Vector (COV). The 5D interpolated COV panels show a significant improvement to the 3D interpolation results. With the incorporation of vintage data and implementation of 5D interpolation, the multiple predictions were improved.
After applying 3D SREM on the data, 3D interbed demultiple was implemented assuming that the dominant multiple periodicity at the target level is related to two shallow reflectors which have approximately 138ms TWT separation. As the real shallow data was too poor to use, full waveform inversion velocities were used to model the reflectivity of the shallow overburden, which used as input for 3D interbed multiples prediction together with the actual data. This 3D data and model driven approach successfully predicted the 1st order interbed multiples bouncing between these two reflectors.
This advanced 3D de-multiple approach has significantly attenuated multiples at target level allowing more reliable interpretation of the reservoir sections. Robust data interpolation and optimal implementation of novel multiple attenuation techniques were the key elements to the success of this project. Following the same processing approach on surveys or data with similar issues and challenges will help to address the seismic multiples and improve the reliability and accuracy of reservoir interpretation.