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IPTC 2014: International Petroleum Technology Conference
- Conference date: 19 Jan 2014 - 22 Jan 2014
- Location: Doha, Qatar
- Published: 19 January 2014
341 - 354 of 354 results
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Permeability Prediction Using Probabilistic Neural Network (PNN): Application to the Paleozoic Shallow Marine Sandstone of Quwarah Member, Qasim Formation, Saudi Arabia
Authors O. Abdullatif and M. ShuaibThis outcrop analog study was conducted on surface equivalent to the Quwarah member of the middle to late Ordovician of Qasim Formation in central Saudi Arabia. The Paleozoic section contains important oil and gas reservoirs with more to explored and developed mainly related to unconventional tight gas and shale gas. The main objectives of this work is to use the probabilistic Neural network (PNN) to predict permeability of the Quwarah sandstone on the basis of systematically collected and petrographically estimated textural and compositional data from the outcrop sections of the Quwarah member. The results show that probabilistic neural network (PNN) was capable of reproducing permeability with very high accuracy, so that the calculated correlation coefficient for permeability was 0.89. This outcrop analog study, when integrated with subsurface data, might provide database, reveals heterogeneity and enhances understanding and better prediction of reservoir quality in the subsurface.
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Pore-Scale Imaging of Oil and Wettability in Native-State, Mixed-Wet Reservoir Carbonates
Authors N. Dodd, R. Marathe, J. Middleton, A. Fogden, A. Carnerup, M. Knackstedt, K. Mogensen, X. Marquez, S. Frank, N. Bounoua and R. Noman3D pore-scale imaging and analysis provides an understanding of microscopic displacement processes and potentially a new set of predictive modeling tools for estimating multiphase flow properties of core material. Reconciliation and integration of the data derived from these models requires accurate characterization of the pore-scale distribution of fluids and a more detailed understanding of the role of wettability in oil recovery. The current study reports experimental imaging progress in these endeavors for a preserved-state carbonate core from a Middle Eastern waterflooded reservoir. Micro-CT methods were used in combination with novel fluid X-ray contrasting techniques and image registration to visualize the 3D pore-scale distribution of residual oil in mini-plugs. Segmentation of the registered tomograms and their differences facilitated estimation of the residual oil saturation. These predictions from digital analysis agreed reasonably well with laboratory measurements of oil saturation from extraction of sister mini-plugs and spectrophotometry. The tomogram segmentations provide additional information beyond this average value, such as the fractions of oil associated with macroporosity and microporosity. After the tomogram acquisitions, one of the dried mini-plugs was cut and SEM imaged at this exposed face to provide 2D images of fine features below the micro-CT resolution limit, such as the characteristic dimpled texture of asphaltene films on calcite surfaces due to their local wettability alteration in the reservoir. A new registration procedure was developed to embed the SEM images from the cut plug into the tomogram of the original uncut plug at their correct locations, so that this high-resolution wettability information could be integrated into the 3D pore network description and correlated to the local distribution of residual oil.
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Advanced HPCT Abrasive Perforating Technique Utilized to Successfully Bypass Damaged Formation to Allow for Effective Acid Stimulation
Authors A.R. Malik, M.S. Buali, T.M. Ogundare, A.E. Mukhles, T. Green and M. HaekalThis paper will discuss how an advanced technique of abrasive perforating with high pressure coiled tubing (HPCT) was utilized to bypass damage that existed in the open hole section of the well-bore as a result of a recent descaling operation. The well discussed in this paper had extensive scale and therefore required coiled tubing (CT) intervention to clean the wellbore. Following the scale cleanout, a matrix bullhead acid job was performed to bring the well back to production. Some +nonacid soluble scale remained in the wellbore was pushed into the formation ahead of the matrix treatment. As a result, no incremental gains were achieved after the acid treatment. After analysis of the cleanout, stimulation data and results, it was determined that the cause of the now poor production was scale debris plugging the formation. As the scale was not 100% acid soluble, the team chose to use an abrasive perforating tool with HPCT to bypass the suspected damage. Fifteen stages of perforation were successfully conducted using HPCT Advanced Abrasive Perforating Technique in a single run in depleted carbonate reservoir. Following the HPCT abrasive perforating operation, good injectivity was reestablished and the well was successfully stimulated to bring the well back to optimal production.
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Diagnosis of Multiple Fracture Stimulation in Horizontal Wells by Downhole Temperature Measurements
More LessDiagnosis fractured well performance for a multiple-stage fractured horizontal well is critical to understand and improve fracture stimulation design. Production logging tools (PLT) can be used in this problem, and temperature distribution data (by PLT or fiber-optic sensors) is one of the valuable information for performance diagnosis. However, until today quantitative interpretation of dynamic temperature data is still challenging and requires indepth mathematical modeling of heat and mass transfer during production in a complex flow system. In this study we developed a semi-analytical model to predict temperature and pressure behavior in a multiplefractured horizontal well during production. The tri-linear model is used to simulate flow in a fracture system for horizontal wells. The model can be applied for single phase oil or gas wells. For gas well, the non-Darcy effects are considered by permeability alteration using minimum permeability plateau. Flow in the wellbore is modeled under unsteady state condition modified from a steady state horizontal wellbore model presented before. This coupled model for fracture flow and wellbore flow can predict the pressure gradient along fracture and also the pressure and flow rate distribution in the wellbore. The thermal model calculates the heat transfer in the fracture/reservoir/wellbore system considering subtle temperature changes caused by the Joule-Thomson cooling and frictional heating effects. The fluid properties are set as functions of in-situ pressure and temperature. The result shows that transient temperature behavior can be used to estimate the fracture initiation points and length, number of created fractures and distribution of fluid along the wellbore. The temperature is sensitive to the flow rate distribution along the wellbore, the fracture geometry, and also the fracture conductivity. With the developed method, we can evaluate the fracture treatment by comparing the designed fracture half-length with the generated fracture-length. When applied in history match of production data, it also can predict conductivity decline as a function of production time.
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Narrowing the Loop for Microporosity Quantification in Carbonate Reservoirs Using Digital Rock Physics and Other Conventional Techniques - Part II
Authors A.A. Al-Ratrout, M.Z. Kalam, J.S. Gomes, M.S. Jouini, S. Roth, H. Lemmens and B. MtawaaMicroporosity quantification is becoming increasingly important to assess the distribution of hydrocarbons and their remaining/residual saturations after water flood (and /or gas flood). Assessing uncertainties and limitations in microporosity estimations of carbonate cores, comprising different reservoir rock types have been a challenge for geoscientists. The advent of Digital Rock Physics (DRP) based measurements allow the pore 3D network images from micro and nano - Computed Tomography (CT) scans on selected sub-samples to map representative cores and Reservoir Rock Types (RRT). The DRP based microporosity is rigorously examined and compared with other techniques/tests. In Part I (Al-Ratrout, Kalam, Gomes, & Jouini, 2013) we presented conventional techniques, such as Mercury Injection Capillary Pressure (MICP), Nuclear Magnetic Resonance (NMR), Thin Section (TS) and Backscattered Scanning Electron Microscopy (BSEM) are used for semi-quantitative evaluations of microporosity. Images at different magnitudes (4X, 10X, 40X and 100X) were captured from TS and BSEM, and used to quantify porosity using image analysis software. NMR and MICP measurements acquired through a commercial laboratory were also analyzed to quantify the microporosity. DRP based 3D pore network images have been acquired at different scales of interrogation from nano to micro meters to define microporosity. In this paper we examine DRP results based on three state-ofthe- art techniques, such as Pore-Network Fusion, to combine micro and nano-CT to enhance microporosity estimations. Cutting edge nano level investigation involving Focused Ion Beam Scanning Electron Microscopy (FIB-SEM) and last technique is the 2D Large Mosaic Image using modular automated processing system (Maps). This work has shown DRP to be as excellent tool to assess microporosity, and quantify the microporosity effectively in 3D pore network. The evaluation with conventional techniques demonstrated the current industry limitations and uncertainty.
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Secondary and Tertiary Polymer Flooding in Extra-Heavy Oil: Reservoir Conditions Measurements - Performance Comparison
Authors C. Fabbri, C. Cottin, J. Jimenez, M. Nguyen, S. Hourcq, M. Bourgeois and G. HamonIn the challenging context of heavy to extra heavy oil production, polymer flood technology appears to be a promising solution to enhance ultimate recovery of reservoirs. Several field applications have already shown the efficiency of such technologies, although the final incremental recovery and mechanisms involved are still poorly understood. Indeed, the characteristics of the viscous fingering effects that certainly play a role are rarely captured at the field scale or at the core scale. This work aims at comparing the results of two core experiments with polymer flood in secondary and tertiary mode, in reservoir conditions, in term of recovery as well as in terms of relative permeabilities. In both cases, experiments were carried out on reconstituted reservoir cores, with restored wettability, initially saturated with live oil partially degassed in a PVT cell to the expected pressure and viscosity at the start of the field test. Saturation profiles were measured with X-Ray scans; effluents were collected in test-tubes and analyzed by UV measurements. Additional follow-up with tracers was tested in order to better assess the breakthrough of different fluids as well as the polymer adsorption during the experiment. Although the viscosity ratio was still highly unfavorable, with a polymer bulk viscosity around 70 cP at 10s-1 and an oil viscosity estimated at 5500 cP, polymer floods exhibit an excellent recovery factor.
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Imaging The Pre-khuff: Changing The Game With Innovative Seismic Technology
Authors M. van der Molen, C. Harvey, M. Molinaro, R. Navarro-Luna and P. StigborgThis paper describes how QSUI was able to overcome some of the significant geophysical challenges associated with Pre-Khuff exploration. On legacy seismic data, strong multiples from the layered carbonate overburden overwhelm the relatively weak primary reflections from the deep Pre-Khuff clastics. In order to identify and understand the main generators of coherent seismic noise, Qatar Shell Upstream International (QSUI) has undertaken seismic modeling using VSP data, legacy shot records and full-waveform synthetic modeling. Results of this work informed the reprocessing of existing seismic and the design of a 3D Ocean Bottom Cable (OBC) seismic survey. The acquisition of dual component (2C) Wide-Azimuth (WAZ) OBC data, together with state-of-the art in-house seismic processing led to a break-through in seimsic imaging of the Pre-Khuff reservoir layers. This has demonstrated that the geologic intervals below the Hercynian unconformity exhibit a steeper dip compared to the overlying Khuff and younger sediments, as expected by the geologists and observed in neighboring countries.
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Utilising Integrated Natural Gas Liquids (NGL) and Nitrogen Rejection unit (NRU) technology in Qatar on the Barzan Gas Project
More LessIntegrated Natural Gas Liquids/Nitrogen Rejection Unit (NGL/NRU) technology will be utilised for the first time in Qatar on the Barzan Gas Project, which is a joint venture project between Qatar Petroleum (QP) and ExxonMobil Barzan Limited. The North Field Reservoir, which supplies the Barzan Gas Project, contains a high content of inerts, e.g., nitrogen and helium. One challenge was to identify a technology to achieve the required specifications of the sales gas by rejecting the inerts from the feed gas. RasGas initiated a study to evaluate process licensors’ capability to supply an integrated process design for recovering NGL and rejecting nitrogen for the Barzan Gas Project. The requirements are to recover the NGL product stream, containing 95% of the incoming ethane content and essentially 100 per cent of the propane and heavier (C3+) hydrocarbons. One primary component of the technology is to reject nitrogen from the gas stream to achieve an acceptable BTU content and Wobbe Index to meet QP sales gas specifications. To achieve the above requirements, Chart Energy and Chemicals Inc, as a technology licensor, demonstrated the ability to provide an integrated NGL/NRU licensed process with the following merits: • Utilises a proven Brazed Aluminum Heat Exchanger (BAHX) supplier. • Takes advantage of the available feed pressure to minimise overall energy consumption without requiring excessive Aluminum / surface area. • Utilises high efficiency compression to meet final sales gas delivery requirements. • Minimises footprint and plant congestion by installing equipment within sealed cold boxes. • Provides a simple exchanger arrangement for easy conversion to various modes of operation.
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A Hurt-Based Approach to Safety
Authors R.M. Smith and M.L. JonesThis paper describes the Hurt-based Approach to Safety that ExxonMobil’s Upstream Companies use in personnel safety management. Traditionally, ExxonMobil has primarily used industry standards driven by the U.S. Occupational Safety and Health Administration (OSHA) to classify safety events based on the treatment and/or restrictions provided. However, this treatment-based approach has limitations. With intense focus on administrative reporting (i.e., is the incident recordable or not?) and incident escalation management, the approach does not naturally resonate with workforce members to enable desired cultural changes. Also, historical approaches have not included a potential consequence assessment; a critical element in preventing future injuries. Incident classifications are often inconsistent because work restrictions and medical treatments are subject to individual medical provider judgment. ExxonMobil has created a Hurt-based Approach to mitigate limitations of the treatment-based approach. This paper discusses the history of ExxonMobil’s “Hurt Free” philosophy and explores benefits: natural safety language of humans; protect family, prevent injuries consistent description of actual injury severity integral assessment of potential injury severity resonates with workforce to enable cultural changes based on caring for people alignment with Exxon Mobil Corporation’s safety vision of “Nobody Gets Hurt” These benefits, along with passionate safety leadership and Hurt-based metrics, are critical elements in ExxonMobil Upstream’s safety management systems. While many companies have some of these elements in their programs, it is the combination of all elements that drive ExxonMobil’s Hurt-based Approach. This paper will share ExxonMobil’s expectations of safety leaders and insight into how a Hurt Free philosophy leads to higher levels of understanding and promotes safety leadership throughout the organization. It will describe how a Hurt-based Approach provides a more natural line of sight for assessing incident potential and provides a more natural and caring interaction with injured parties; thereby, creating a more positive personal safety culture. It will describe how potential consequence is determined and how this potential drives the prioritization of resources, incident assessments, work activity focus, etc. It will detail ExxonMobil’s “Mining-the-Diamond” initiative which provides increased focus on high consequence potential work activities that could result in life-altering injuries or death. Trend analysis will be provided to illustrate continuous improvement efforts.
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Establishing Higher Oil Production Capabilities: Engineered Approach Achieves Longest Lateral Hole Section in Kuwait
Authors H. Al-Ajmi, N. Al-Barazi, A.-A. Al-Rushoud, R. Trivedi, H. Maliekkal, O. Ghoneim, M. Saleh and P. NairKuwait Oil Company (KOC) is analyzing the feasibility of utilizing extended reach drilling to achieve a long lateral section to increase oil production in northern Kuwait. Several attempts were made to accomplish the objective with roller cone and PDC bits on various directional tools with limited success. The major problem was short bit life/cutting structure durability and steerability issues in the difficult Mauddud carbonate reservoir. A drilling optimization initiative would benefit the entire northern Arabian basin because Mauddud is an important oil reservoir with uniform thickness and extensive regional distribution. Offset analysis showed three to four TCI bits were required to drill 3000 ft of lateral hole section. PDC bits display increased durability making up to 2500 ft of hole but were pulled for low ROP and unacceptable drilling inefficiency before reaching TD. A second PDC was required to finish the lateral and gain sufficient access to the reservoir. Before the optimization project, the longest single run with PDC was 2935 ft. The average footage drilled by roller cone TCI is approximately 1500 ft with average PDC footage around 2500 ft. To improve PDC bit performance, a rock strength program was run to identify the unconfined compressive strength (UCS) of Mauddud for use in an FEA-based modeling system. The software pegged the formation’s UCS range between 9-15 kpsi with peaks up to 24 kpsi. Analogous rock sample files were selected and laboratory tests were performed to duplicate fundamental shearing action under the appropriate confining pressures. The resulting data was entered into the modeling system and simulations were performed with a baseline PDC to identify how lithology influences the bit/BHA and to investigate was to mitigate destructive drillstring dynamics. The engineering study produced a six-bladed PDC that drilled the longest lateral interval (5250 ft) in Kuwait through Mauddud. The bit displayed excellent steerability and completed the hole section without losing ROP. This resulted in 100% footage improvement against offset PDC runs and is more than 150% better than the best TCI performance. The completed well has provided a 200% increase in production capabilities making up to 4500 bbls/day.
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A Dynamic Imaging Particle Analysis System for Real-Time Analysis of Drilling Muds
Authors L. Brown, M. Duplisea and S. BowenThis paper details a novel new system for real-time analysis of drilling muds. The system uses in-flow digital imaging to capture images of all particulates in drilling mud. Sophisticated image processing algorithms are used in real time to segment each particle from the background, and record over 30 size, shape and gray-scale measurements for each particle. Particle size and shape distributions are produced in real-time, and are used for trend analysis. This system can be integrated into any part of the drilling flow loop for analysis at any point in the process. Using a unique auto-dilution system, the concentration is automatically adjusted for optimum presentation of the particulates to the imaging system. Since every particle image and its measurements are saved by the system, it creates an ironclad audit trail for how particle size distributions are derived. While the basic system architecture is very robust and could be used in many different applications, the system presented here has been fully optimized for the analysis of particulates in drilling mud. Real-world data collected in the field is shown illustrating typical results from the system. A brief description is provided on how the system works in real-time, including how the particle images are acquired and measurements made. Finally the results of the analysis are shown, detailing how the system can be used to monitor particle size and shape distributions from any part of the flow loop. This resulting analytical data becomes an integral part of the real-time operation of the drilling platform, ensuring continuous optimization of the drilling mud particulate content. This optimization is critical to the performance of the drilling mud, for cooling and lubrication of the drill bit, interacting with the surrounding geology and maintaining proper rheological characteristics. This system represents a new way of proactively monitoring drilling mud content in real-time, and provides more information than prior systems because the system can measure particle size as well as shape. Particle shape information can be used by the system software to automatically classify particulates into different component types.
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Approximations of Primary, Secondary and Tertiary Recovery Factor in Viscous and Heavy Oil Reservoirs
Authors R. Kaczmarczyk, J. Herbas and J. Del CastilloLimitations in the availability of methods to estimate recovery factor at the initial stage of petroleum exploration pushes for investigation new ways of analysing available datasets. This work investigates empirical and volumetric methods to estimate recovery factors in viscous and heavy oil reservoirs. It also investigates newly available advance screening methodology to determine tertiary/ultimate recovery factor in these reservoirs. Initially, primary recovery factor was estimated based on field analogy. Secondary recovery factor was calculated using empirical equations. In the second, main part of this work, ultimate recovery factor was approximated using data mining/machine learning approach to reveal eventual trends in viscous or heavy oil databases. Information contained within this project was used to estimate recovery factors in certain viscous oil reservoirs at the initial stage of exploration. However, after reformatting original data base, advance screening methodology would be potentially applicable to any viscous or heavy oil reservoir around the world. It was found during the project that the primary recovery factor can be successfully estimated based on the field analogy. Empirical methods can be applied in some cases. The quality of the obtained results depends on whether they were derived for conventional or heavy oil reservoirs. Based on advance screening, it was shown that tertiary/ultimate recovery factor can be successfully estimated. Final product includes development of a methodology on how to approach the recovery factor approximation in viscous or heavy oil reservoirs without production history or at early stage of the field life.
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Drill Pipe Connection Technology Enables Saudi Aramco & Precision Drilling to Deliver the Longest Horizontal Well in Saudi Arabia
Authors A. Iravani, M. Hanafi, S. Al-Shehry, G. Plessis and N. MohamedRecently in Saudi Arabia, a national drilling record was reached for the longest horizontal well drilled. A key technology for drilling such wells, which typically show a Total Depth (TD) in excess of 30,000 ft, was the use of extended reach horizontal drilling. Drilling these wells required, among other things, a proper selection of drill stem products. With drill pipe accounting for most of the string length, choosing the right specification plays a huge role in overall drilling performance. With a lot of friction as the string is ran downhole, the ability to transmit torque to the bit is challenging and connection technology becomes critically important. Double shoulder connections place connections at par with the pipe body in terms of torque capacity and actually come with additional benefits. Not only do these connections transmit higher torque but they do it using a thinner steel envelop, which allows a larger internal opening for improved hydraulics. Furthermore, these streamlined connections can also come with reduced Outside Diameter (OD) tool joints which help keep the Equivalent Circulation Density (ECD) as low as necessary to maintain formation integrity. Towards the end of 2010, a national record 32,136 ft measured depth well was drilled in Saudi Arabia using such connection technology, proper material grade selection and optimized pipe size selection. The well was then used for horizontal water injection into the reservoir in order to maintain reservoir pressure and optimize production. This paper will describe the challenges of this project and how connection technology, engineered material grade and pipe size helped address each of these challenges. The record well case history will form the base of this paper and authors will include a comprehensive section on the successfully selected connection, its performances as well as a summary of more recent results.
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Long Term Wellbore Isolation In a Corrosive Environment
Authors O.R. Ilesanmi, B. Hilal, S. Gill, A. Brandl, M. Al Mazrouei and A. AbdullahThe paper reviews two case histories about successful wellbore isolation with a suitable cementing system for a recent enhanced oil recovery / CO2 project targeting the Thamama B formation of the Bab Far North reservoir in the UAE. The first two wells were vertical observers with zonal isolation required between the Thamama A and B. These wells were expected to exhibit a naturally corrosive environment (e.g. 56,000 ppm of CO2). To address these challenges, a fit-for-purpose cementing system, suitable for CO2 and other corrosive fluids, was developed and successfully applied. The system was designed to isolate and protect specific Thamama zones and wellbore areas that contained gaseous or liquid corrosive CO2. This cement slurry was developed with a density of 16.7 ppg exhibiting expanding properties after setting to compensate potential shrinkage issues and to improve cement bond. Laboratory test results for the developed cementing system, such as compressive strength development, thickening time, expanding properties after setting, and integrity after long term exposure towards wet CO2, are presented and discussed. Performance requirements for cementing sytems to qualify for CO2 tolerance are elucidated. Finally, the execution in the field and the quality of the cement job was evaluated. All of the special designs exhibited excellent bond log results. The favorable lab test results and the positive case history conclude that the developed cementing system can be a viable solution to provide long term zonal isolation in a wellbore with a corrosive environment.
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