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Results
Abstract A new robust metaheuristic optimization method, namely modified cuckoo search (MCS), is presented in this paper. MCS is inspired by breeding behavior of cuckoo birds and combined with Lèvy flight approach to efficiently search for optimal solutions. MCS is coupled with a filtering technique to provide the ability to handle nonlinear constraints. The filter-based MCS is efficient insofar as it provides a bias toward exploration during early generations allowing for global search and then shifts that bias toward exploitation at final generations allowing to search promising areas of the solution. This helps in finding feasible solutions at earlier search stages and consequently improves convergence rate. Two example cases involving two-dimensional synthetic reservoir models are presented. The first case compares the performance of MCS to that of genetic algorithm (GA) to maximize oil recovery by optimizing the location of four injection wells. It is shown that MCS outperforms GA in terms of the optimal solution as well as the rate of convergence. The second case entails the use of filter-based MCS to maximize NPV under maximum water cut constraint at the production well. The results indicate the superior performance of the filter-based MCS as it was able to quickly find feasible solutions even though all previous initial solutions were infeasible. The incorporation of filtering technique allows to assess the sensitivity of the objective function to the constraint violation. This provides additional insights that can lead to better future planning.
- North America > United States (1.00)
- Asia > Middle East > Saudi Arabia (0.68)
Abstract Unconventional shale reservoirs differ largely from conventional sandstone and carbonate reservoirs in their origin, geologic evolution and current occurrence. Shale is a wide variety of rocks that are composed of extremely fine-grained particles with very small porosity and permeability values in the order of few porosity units and nano-darcy range, respectively. Shale formations are very complex at the core scale, and exhibit large vertical variations in lithology and Total Organic Carbon (TOC) at a small scale that renders core characterization and sweet spot detection very challenging. Shale formations are also very complex at the nano-scale pore level where the pores have different porosity types that are detected within the kerogen volume. These complexities led to further research and development of advanced application of high resolution X-ray CT scanning on full diameter core sections to characterize shale mineralogy, porosity and rock facies so that accurate evaluation of the sweet spot locations could be made for further detailed petrophysical and petrographic studies. In this work, argillaceous shale gas cores were imaged using high resolution dual energy X-ray CT scanning. This imaging technique produces continuous whole core scans at 0.5mm spacing and derives accurate bulk density and effective atomic number (Zeff) logs along the core intervals which were crucial in determining lithology, porosity, and rock facies. Additionally, integrated XRD data and energy dispersive spectrum (EDS) analysis were acquired to confirm the mineral framework composition of the core. Smaller core plugs and subsamples representing the main variations in the core were extracted for much higher resolution X-ray CT scanning and Scanning Electron Microscopy (SEM) analysis. Porosity was mainly found in organic matter and was determined from 2D and 3D SEM images by image segmentation process. Horizontal fluid flow was only possible through the organic matter and the simulations of 3D FIB-SEM volumes by solving Stokes equation using Lattice Boltzmann Method (LBM). A clear trend was observed between porosity and permeability while correlating with identified facies in the core. Silica-rich facies gave higher Phie-K characteristics compared to the low clay-rich facies. This is mainly caused by pressure compaction effect in the soft clay-rich samples. High percentages of organic matter were not found to be good indication for high porosity or permeability in the clay-rich shale samples. The depositional facies was found to have great effect on the pore types, rock fabric and reservoir properties. The results and interpretations entailed in this study provide further insights and enhance our understanding of heterogeneity of the organic rich shale reservoir rock.
- North America (0.93)
- Asia > Middle East > Saudi Arabia (0.68)
- Europe > Norway > Norwegian Sea (0.45)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Greater Peace River High Basin > Sinclair Field (0.93)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
Sweet Spot Identification and Optimum Well Planning: An Integrated Workflow to Improve the Sweep in a Sector of Giant Carbonate Mature Oil Reservoir
Al-Sada, Abdullah I. (Saudi Aramco) | Bouaouaja, Mohammed T. (Saudi Aramco) | Al-Hhuthali, Ahmed H. (Saudi Aramco) | Al-Safi, Abdullah A. (Saudi Aramco)
Abstract This study illustrates a comprehensive-integrated approach to identify the potential locations for future development in a sector area of a giant carbonate mature oil reservoir. The approach uses various data from several sources including reservoir surveillance, production performance, geological interpretation and numerical simulation and cohesively combines them to yield an informed decision to assess field development and management. The study area is under peripheral waterflood for more than fifty years and dominated by heterogeneity related to fracture corridors, high permeable zone, and reservoir zonation. These features leads to a preferential and uneven propagation of water flow which results in un-swept oil bearing spots using the existing wells lay-out and configuration. The reservoir management team has developed an integrated workflow to address these challenges by using several reservoir engineering methods and models including Water Encroachment, Reservoir Opportunity index, Fractional Flow Calculation, Remaining Volumetric and Water Flow Paths. The designed workflow consists of creating derived attributes that describe these models and filter the sector area to define the sweet spots. The selection and prioritization of the defined sweet spots are supported by available reservoir surveillance and production data. However, the scarcity of reservoir surveillance and production data in some areas of the sector, motivated reservoir management team to stretch the limits by capitalizing on gas wells penetrating the shallower oil reservoirs. The open-hole logs of these wells recorded thicker oil column than the preestimated column using the existing surveillance data. As a result of these efforts, a development plan was designed in order to ensure reserves depletion in the identified sweet spots by drilling new wells or sidetracking the existing wells. Despite the level of maturity, simulation forecasts indicate that the area of interest has lot of potential to sustain a high production rate.
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Mauddud Formation (0.99)
- (3 more...)
Abstract Reservoir monitoring is an important aspect of prudent reservoir management to sustain productivity and achieve higher hydrocarbon recoveries. Monitoring is a process that comes in various forms, such as that of flood front advancement and reservoir saturation changes and quantification. Designing and implementing an effective monitoring program to track fluid advancement and quantify remaining oil saturation is a reservoir management best practice that ensures optimum sweep is achieved; and so is crucial for all fields, regardless of their state of maturity. The necessity for such programs becomes more critical as fields mature. Reservoir saturation monitoring programs are usually faced with several challenges, including: mixed and low fluid salinity, tool limitations, borehole conditions and reservoir heterogeneity. Overcoming these challenges requires comprehensive programs that encompass adoption and integration of various derived saturation techniques. This paper will discuss a reservoir monitoring program of a large carbonate field that has produced continuously for several decades. The monitoring program includes "key monitoring wells" in addition to drilling new evaluation wells that are strategically selected and are mostly located in well flooded areas. Time-lapse production and fit for purpose saturation logs are run in the existing wells, while extensive in situ measurements of fluid saturation are collected in the case of the new wells, to monitor saturation changes and track the movement of fluids. The paper will also discuss the various methodologies adopted to address the aforementioned challenges. It will illustrate how the monitoring program has aided in tracking fluid movement, quantitatively determining fluid saturations and assessing sweep efficiency (Ed, Ev and Ea). In addition, the paper will show how the collected information was a catalyst in identifying sweet spots in flooded regions, and therefore guiding development activities for maximizing hydrocarbon recovery, especially from mature areas.
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract As reservoirs approach maturity, the understanding and implementation of Enhanced Oil Recovery (EOR) techniques become essential to meet the world growing oil demand. EOR processes involve the displacement of one fluid by another. The major EOR methods in the petroleum industry include thermal, miscible and chemical processes. Miscible displacement methods involve the injection of solvents that will inter-mix with the reservoir oil to increase its mobility and reduce the oil saturation to low values in the swept zone of an oil reservoir. This work is part of Kuwait strong focus on EOR applications in Kuwaiti reservoirs to maximize the hydrocarbon recovery factors for a sustainable growth in oil production. This study is an experimental study that evaluates and investigates the miscible flood performance in Kuwait. An oil formation was selected as a candidate reservoir for this study after conducting EOR screening criteria. Core and fluid samples were collected and their properties were evaluated. Slim tube experiments were conducted to measure the oil minimum miscibility pressure with CO2. Coreflooding experiments were conducted to evaluate the recovery factor from different injection scenarios. The experimental injection scenarios included the effect of several design parameters including WAG ratio, number of cycle per WAG and the total slug size. These parameters showed different effects on the recovery factor. Optimum injection scenario was obtained which gave the highest recovery factor (WAG 1:2, number of cycle 2 and total slug size 0.4PV). In this study, the in-situ miscibility achievement was quantified and evaluated at different injection scenarios. The outcomes of this work provide valuable information for future miscible flood field implementation.
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Minagish Field > Marrat Formation > Upper Marrat Formation > Sargelu Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Minagish Field > Marrat Formation > Upper Marrat Formation > Najmah Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Minagish Field > Marrat Formation > Upper Marrat Formation > Marrat "C" Formation (0.99)
- (9 more...)
Optimization and Post-Job Analysis of the First Successful Oil Field Multistage Acid Fracture Treatment in Saudi Arabia
Almubarak, Tariq (Saudi Aramco) | Bataweel, Mohammed (Saudi Aramco) | Rafie, Majid (Saudi Aramco) | Said, Rifat (Saudi Aramco) | Al-Ibrahim, Hussain (Saudi Aramco) | Al-Hajri, Mohammad (Saudi Aramco) | Osode, Peter (Saudi Aramco) | Al-Rustum, Abdullah (Saudi Aramco) | Aldajani, Omar (Saudi Aramco)
Abstract Multistage acid fracture treatments are utilized in low-permeability carbonate reservoirs (permeability <10 md) to stimulate the formation by creating highly conductive fractures in the formation and bypassing near wellbore damage. The fracture is generated at high pressures that are required to break the rock open while using a viscous pad. The fracture is then kept open by adding gelled or emulsified acid to create uneven etches on the surface of the fracture. Pre-job acid fracturing treatment fluids’ reaction and compatibility analysis in the laboratory are crucial as the operational success is highly dependent on its chemicals’ reactions. The key problem with acid fracturing treatments is the difficulty in appraising the actual downhole reactions and performance of the treatment chemicals within the heterogeneous rock. This problem can be resolved when flow back fluids and the chemical ions are analyzed to understand the reactions that occurred down hole. Also, since acid fracture treatments require pumping large volume of fluids, flowing back the entire fluids becomes a challenge due to the low reservoir permeability and the associated reservoir rock capillary pressure effects. This paper will discuss the pre-fracture treatment evaluation based on laboratory experiments - core flood, rock dissolving capacity, and fluid compatibility in addition to comparing the expected chemical ion returns with the actual ions observed in the flow-back fluids. The results of this flow-back fluid analysis showed a recovery of 17% of the chemicals pumped during the treatment with a stabilized production rate of 3 MBOPD. Further water analysis indicated the presence of 25-30% formation water while the critical ions analyzed showed the effectiveness of the corrosion inhibitor package, acid system dissolving capacity, and crosslinker fluid recovery. It is expected that this paper will provide a learning process for optimizing future multistage acid fracture treatment in Saudi Arabia.
- North America > United States (1.00)
- Asia > Middle East > Saudi Arabia (1.00)
- Geology > Geological Subdiscipline (0.66)
- Geology > Mineral > Silicate > Phyllosilicate (0.48)
Lessons from the First Successful Oil Producer Multistage Acid Fracturing in Saudi Arabia: The QA/QC Process from the Laboratory to the Field
Almubarak, Tariq (Saudi Aramco) | Bataweel, Mohammed (Saudi Aramco) | Rafie, Majid (Saudi Aramco) | Said, Rifat (Saudi Aramco) | Al-Ibrahim, Hussain (Saudi Aramco) | Osode, Peter (Saudi Aramco) | Alfaifi, Mohammed (Saudi Aramco) | Alenizi, Sultan (Saudi Aramco) | Aldajani, Omar (Saudi Aramco) | Karadkar, Prasad (Halliburton)
Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Saudi Arabia Section Annual Technical Symposium and Exhibition held in Al-Khobar, Saudi Arabia, 21-24 April 2014. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract The increasing demand for energy has extended the development horizon towards relatively tighter formations. However, experience has shown that the most successful technique to optimize production from these tight carbonate formations would require multistage acid fracture stimulation treatment. Generally, laboratory tests, computer simulation and technical expert opinions yield optimistic results which are not always replicated in the field due to the absence of strong QA/QC follow-up. This field support was considered critical for a recent multi stage acid fracture treatment which involved many variables and fluid additives in an onshore Saudi Arabia multi-lateral well. This report will discuss the pre-job laboratory tests and fluid optimization process which included core flooding, compatibility, stability, and rheology tests. In addition, this paper will outline the QA/QC process adopted throughout the various operational stages and provide flowchart as recommendations for subsequent multistage acid fracture treatments in the field. Also presented is a case study from the first successful oil field multistage acid fracture treatment in Saudi Arabia. Laboratory results obtained reflected the negative impact of increased salinity on the crosslinked viscosity.
Abstract The growing demand for gas in the Kingdom of Saudi Arabia and the availability of multistage fracturing (MSF) of horizontal well technology have opened up the development of tight gas reservoirs throughout the country. Draining the reservoir efficiently using MSF strongly depends on well spacing, especially for low permeability reservoirs. The majority of the work done by the industry to find the optimum well spacing was based on economic considerations. Saudi Aramco optimizes field development based on sustained rate and ultimate hydrocarbon recovery. Natural gas is treated as one of the most essential commodities supporting the country's infrastructure based on the increased domestic energy demand. Some of the significant parameters to consider for well spacing optimization are the drilling azimuth and well completion strategy that include a number of induced fractures, fracture conductivity, and fracture half-lengths. In addition, reservoir properties, such as formation thickness, reservoir permeability, and the permeability anisotropy ratio are to be considered. Due to the scarcity of interference test data in gas wells and the inaccuracy of analytical solutions, numeric simulation is the most suitable approach for such a study. To find the optimum well spacing, several simulation runs are carried out for a realistic range of well and reservoir variables. The outcomes are then translated into a 20-year cumulative production as a function of the well spacing, with the results indicating that lower permeability reservoirs require closer well spacing. In the case of a large number of long fractures, wells need to be placed further away from each other to minimize well interference. This paper gives the recommended MSF horizontal well spacing for several development scenarios in Saudi Arabian gas reservoir environments. Although each area must be individually studied and optimized, the results will provide engineers with guidelines to better plan gas field development with the application of MSF technology.
- North America (1.00)
- Asia > Middle East > Saudi Arabia (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (0.54)
Characterization of Next-Generation Heavy Oil of Tar Mats in Carbonate Reservoirs and Understanding Its Role in Reserve Estimation and Oil Recovery Economics
Almansour, Abdullah (Missouri University of Science & Technology) | Al-Bazzaz, Waleed (Kuwait Institute for Scientific Research) | Saraswathy, Geetha (Kuwait Institute for Scientific Research) | Almohsin, Ayman (Missouri University of Science & Technology) | Bai, Baojun (Missouri University of Science & Technology)
Abstract The study presented here examined a Kuwaiti reservoir that is classified as a next-generation extreme heavy oil tar-mat reservoir. Successful pyrolysis experiments were performed on carbonate rock containing 33.51% total organic content (TOC). Comparable toluene solvent, water extraction, and surfactant solution extraction had successful but different hydrocarbon recovery yields under different temperature settings. The tar-mat flow was extremely viscous, with a measured "API density close to 1.34 and calculated flow mobility close to zero. Depending on the type of extracting agent applied, increasing the temperature cracked the extreme heavy oil tar-mat available in the carbonate rock, hence improving the extremely viscous nature of the solid residue and causing it to be mobile so that it could flow and be recovered. Four carbon-density flow regimes were identified in this extreme heavy oil tar-mat composition mix, including the free hydrocarbon type I composition (C1–C15), the light hydrocarbon type II composition (C15–C40), the heavy hydrocarbon type III composition (>C40), and the insoluble carbon-residue type IV material (NSO). Each flow regime exhibited a unique recovery potential within the extremely viscous composition mix. A detailed characterization of this tar-mat sample confirmed that the release of trapped type I, type II, and type III compositions from the carbonate pore space was possible, while type IV residue remained resistant to flow, and hydrocarbon retention on the rock was difficult to overcome with the suggested recovery treatments.
- North America (0.68)
- Asia > Middle East > Saudi Arabia (0.28)
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.46)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.93)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (0.95)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (0.91)
Nanotechnology Applications To Minimize Geo-Mechanical Related Challenges While Drilling Intercalated Sediments, Western Desert, Egypt
El Sherbeny, Wael (Baker Hughes) | Al-Baddaly, Hesham (Baker Hughes) | Rahal, Ayman (Baker Hughes) | Said, Mohamed (Baker Hughes) | Hardman, Douglas (Apache corporation) | Henry, Todd (Apache corporation)
Abstract Nanotechnology has become the buzz word of the decade! The precise manipulation and control a matter at dimensions of (1 – 100) nanometers have revolutionized many industries including the oil and gas industry. Nanotechnology applications have pierced through different petroleum disciplines from exploration, reservoir, drilling, completion, production, processing and finally to refining. Nanoparticles are the simplest form of the structures with sizes in the nm range. In principle, any collection of atoms bonded together with a structural radius of less than 100 nm can be considered a nanoparticle. The Tiny nature of nanoparticles results in some useful characteristics, such as an increased surface area to which other materials can bond in ways that make for stronger or more lightweight materials. At the nanoscale; size does matter when it comes to how molecules react to and bond with each other. The filter cake developed during nanoparticles-based drilling fluid filtration is very thin, which implies high potential for reducing the differential pressure sticking problem and formation damage while drilling. While drilling shales formations with nanodarcy (nD) permeability, Nanoparticles can be added to the drilling fluids to minimize shale permeability through physically plugging the nanosized pores and suppress the pressure transmission, hence Nanotechnology can provide a potential solution for environmentally sensitive areas where oil-based mud (OBM) historically used as a solution to stabilize shales. Geotechnical challenges normally increase with increasing well inclination due to the highly faulted nature of many of the formations. Pressures and temperatures are typically not excessive but the complex interlayering of shales, sandstones siltstones and limestones results in multiple problems associated with borehole instability. The Paper will reveal all lab work and field procedures for new Nanotechnology additive for wells that have an intercalated lithologies and tight reservoirs. Also paper will reveal the effectiveness of the nanotechnology additives to stabilize hole geometry that is demonstrated by comparison pre-nanotechnology wells and post-nanotechnology wells
- North America > United States (1.00)
- Africa > Middle East > Egypt (0.84)
- Asia > Middle East > Saudi Arabia (0.69)
- Phanerozoic > Mesozoic > Cretaceous (0.93)
- Phanerozoic > Cenozoic (0.68)
- Africa > Middle East > Egypt > Western Desert > Greater Western Dester Basin > Faghur Basin > Safa Formation (0.99)
- Africa > Middle East > Egypt > Western Desert > Alam El Bueib Formation (0.99)
- North America > United States > New Mexico > Permian Basin > Atoka Field > San Andreas Formation (0.98)
- (10 more...)