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GEO 2008
- Conference date: 03 Mar 2008 - 05 Mar 2008
- Location: Manama, Bahrain
- Published: 03 January 2008
321 - 340 of 385 results
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Integration of formation evaluation results with core data and it impact on production in Marrat Formation
More LessThe Marrat Formation has recently been established as a major hydrocarbon reservoir in northern Kuwait. Substantial commercial reserves have been estimated from this Middle Jurassic formation. The formation is composed of a sequence of dense micritic limestone with secondary wackestones, packstones and frequent interbeds with anhydrite, dolomite and rare shale. This presentation shows the results of formation evaluation of complex lithology integrated with core data to obtain the most suitable testing intervals in Marrat Formation. The study was based on the integration of log analysis with conventional core porosity and permeability analyses results, in addition to fracture characterization from core and borehole image data from two wells drilled in
Raudhatain fields Three main Marrat subdivisions were identified: Upper Marrat, Middle Marrat and Lower Marrat. The main reservoir in the formation is the Middle Marrat, which has been subdivided into three units, from top: A, B and C. The subdivision of Middle Marrat was based on presence of fractures, porosity distributions and lithology. Due to the good porosity development and presence of massive fractures, only the B and C units were recommended for testing.
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Lithofacies attributes, reservoir qualities and depositional setting of the Oligocene carbonates, Al-Khod area, Oman
More LessThe Oligocene strata of the Al-Khod area consist of cyclic sedimentation of basal siliciclastic-dominated units that grade upwards to (locally sandy to pure) carbonates. The siliciclastic units (less than 5% of each cycle) vary from poorly-cemented granular conglomerates to coarsegrained sandstone lithofacies (Lf1). The dominant carbonate portion of each cycle is divisible into two parts: a lower biostromal (c. 20–25% of each cycle) and an upper biohermal coral reef facies (c. 70–75%). The biostromes are characterized by inter-beds of laterally discontinuous to continuous lithofacies of algal-foraminiferal packstone/grainstone (Lf2), algae-dominated, meterscale biohermal mounds (Lf3) and peloidal wackestone to floatstone with large Nummulites and Assilina shells (Lf4). Large, partially to completely leached-out mollusks are present throughout the biostromal lithofacies. The biohermal coral reef facies (Lf5) is represented by massive coral framestones (e.g. Stylopora, Poccillopora, Platygyra, Lobophyllia and Galaxea) with subordinate, localized algal mounds. The stacking nature of the strata suggests intermittent basin subsidence with hinterland uplifting. The latter acted as loci of short-term siliciclastic provenance, whereas the former promoted creation of
accommodation space for the prevailing carbonate lithofacies, which evolved from initial stages of stabilization and colonization (biostromal facies) to more developed stages of diversification and domination (biohermal coral reef facies). The diagenetic features of the carbonate facies include marine and shallow burial calcite cementation, micro- and megaquartz cements, meteoric dissolution and localized dolomitization. Amounts of preserved pore spaces vary among the various lithofacies and include large (cm-scale) vuggy (mainly due to mollusk and coral dissolution), inter- and intra-granular and fracture porosity. The coral framestones show the best reservoir qualities with porosity as high as 15–20% and thus suggest the existence of similar porous reefs offshore the Al-Batinah Coast of northeastern Oman.
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Advances in 3-D geologic modeling at Saudi Aramco
Authors Fahad Al-Humam and James R. Wilkins3-D geologic modeling of Saudi Aramco oil and gas reservoirs has evolved over the last three decades. Technical processes have ranged from simple hand-drawn 2-D maps and cross-sections to using the latest, sophisticated 3-D modeling computer software and hardware technology. Early on, 2-D modeling was time-consuming and tedious. Interpretation results took longer to produce and critical decisions regarding drilling and field development were sometimes made at a cost. Later, as newer computer applications became available, modelers have had more technical capabilities designed to better image the subsurface geology and reservoir properties in full 3-D perspective. State-of-the-art technology was always at the forefront of any 3-D geological modeling practice at Saudi Aramco. The use of the geologic models varies from well planning and placement, field development, reserves calculation, strategic field optimization to enhanced field recovery. To leverage the largest gas and oil fields of the world requires embracing up-to-date technology in terms of the most modern modeling applications with high-caliber professionals. The aim of this presentation is to show the major technical advances that 3-D geologic modelers have implemented over the past 30 years with the goal of producing the most accurate representation of the geology of Saudi Arabia’s gas and oil reservoirs. Chronological illustration of modeling techniques will be covered based on the capabilities and limitations of the modeling applications.
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Basin evolution of the Paleozoic successions of Iraq
Authors Ali I. Al-Juboury and Aboosh H. Al-HadidyThe study addresses the basin evolution of the Paleozoic sequences in Iraq. It integrates petrographical and lithological data from deep exploration wells and outcrops in northern Iraq to better understand the sedimentary environments and to evaluate the depositional and tectonosedimentary evolution of the basin. The Paleozoic successions are represented by five intra-cratonic sedimentary sequences. These are dominated mainly by siliciclastic and mixed sedimentary packages, and are separated by
major and minor unconformities. These cycles are: (1) Ordovician cycle, represented by the Khabour Formation; (2) Silurian cycle, represented by the Akkas Formation; (3) Mid- and Late Devonian to Early Carboniferous cycle, represented by the Chalki, Pirispiki, Kaista, Ora and Harur formations; (4) Permian-Carboniferous cycle, represented by the Ga’ara Formation; and (5) Late Permian cycle, represented by the Chia Zairi Formation. The Ordovician Khabour Formation appears to have been deposited in a shallow-marine environment during several transgressive and regressive cycles. The Silurian Akkas shale was deposited in an open-marine environment. The Late Devonian to Early Carboniferous depositional regimes are considered to be continuous and set
in a vast subsiding basin that reflected epicontinental or epeiric seas in a homoclinal ramp setting. The Permian-Carboniferous Ga’ara Formation was deposited in a deltaic to fluvial environment, while the Late Permian Chia Zairi Formation represents carbonate platform deposition. The potential source rocks may include some shale beds of the Khabour Formation, the hot shales of Akkas Formation and the shales of the Ora Formation. The sandstones of the Khabour, Akkas and Kaista formations have good reservoir potential. The Late Permian carbonates of Chia Zairi Formation may be self-sourcing and contain multiple reservoirs. Basin analysis demonstrates the evolution and architecture of the basin and gives an insight into the effects of the Caledonian and Hercynian
epeirogenic movements on the tectonostratigraphy history of the region.
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A geophysical investigation in eastern Abu Dhabi, United Arab Emirates
A geophysical investigation has been conducted to the southeast of the Al-Jaww Plain, eastern Abu Dhabi Emirate. The area underwent numerous deformations, which can be used to model the geological history of Upper Cretaceous and Tertiary structures. The aim of the study was to determine the contact between the Semail Ophiolite and Tertiary carbonate rocks, and a reverse fault that has been imaged by seismic data. Three days were spent acquiring the data. The first two were spent in surveying and gathering the gravity and magnetic data. The final day was spent in collecting seismic data. The gravity and magnetic surveys were acquired along a grid system that runs 70° NE. The interval distance between the grid lines was 200 m with gravity stations
spaced at 100 m and magnetic stations at 50 m. Different corrections were applied to the gravity data including drift, elevation, latitude, free air and Bougaur. For the magnetic data, diurnal and IGRF corrections were applied. ProMax software was used to process the seismic reflection data. From the gravity and magnetic data, contour maps have been produced, which show the distribution of gravity and magnetic anomalies. The gravity contour map indicates the possible location of the reverse fault. The magnetic contour map clearly shows the contact between the Semail Ophiolite and Tertiary carbonates. Also, the seismic reflection data show the possible geometry of the fault. Moreover, the gravity model indicates the contact between the Semail Ophiolite and sedimentary rocks, as well as the approximate position of the reverse fault.
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Compositional modeling of northern Kuwait Jurassic hydrocarbons for GOR and API prediction
More LessThe prediction of fluid properties in reservoirs prior to drilling is important for new prospective areas in order to reduce exploration risk and to estimate petroleum resources. Compositional modelling studies involving Temim 2-D and 3-D software have been carried-out with the objective to predict hydrocarbon composition and properties, and to quantify resources of various reservoirs within the Jurassic succession of northern Kuwait. The Temis 3-D block of northern Kuwait was derived from a previous block developed for a regional study and updated with new structural maps covering a large area including Bahrah, Dhabi, Sabiriyah, Umm-Niqa, Raudhatain and NW Raudhatain. 2-D models were constructed for calibrating the Najmah source kinetics against API gravity and GOR (gas/oil ratio) and oil chemical composition on known accumulations. Temis 2-D was then used to predict hydrocarbon fluid properties potentially accumulated in Jurassic reservoirs under supercritical PVT (pressure-volume-temperature) conditions. In-place resource estimates were derived from map-based Temis 3-D. In the Cretaceous reservoirs the oil’s API gravity ranges between 30° and 34° and the GOR is relatively low. In contrast the oil in the Upper Jurassic (Najmah, Sargelu and Marrat) reservoirs has
an API gravity greater than 45° and high GOR (greater than 5,000 standard cubic ft/barrel). These differences are explained by a model in which the early generated Najmah-sourced oil migrated into the Cretaceous reservoirs through the faulted Gotnia Salt. More mature oil, expelled later from the Najmah source rock, remained trapped in the Upper Jurassic, where it underwent secondary cracking affecting mainly the aromatic and nitrogen, sulfur and oxygen fractions. The Najmah and Sargelu reservoirs rapidly reached hydrocarbon saturation due to their relatively low-storage capacity. The surplus of hydrocarbons spilled downward into the Marrat Reservoir, particularly the Middle Marrat, and occasionally down to the Lower Marrat.
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Seven microseismic projects in Oman: What have we learned?
More LessSince 1999, a total of seven microseismic projects have been acquired by Petroleum Development of Oman (PDO). These were deployed with a range of monitoring objectives including hydraulic fracturing, reservoir compaction and steam injection. In some cases, the projects have proved very successful and are still monitoring today. For other projects, however, they either failed or gave ambiguous results. The failures have been due to poor planning and project management and/or equipment failure. But, in both the successes and failures, PDO has gathered a wealth of knowledge and experience, which are now being incorporated in the planning of upcoming microseismic projects. This knowledge ranged from technical to managerial to operational. In this presentation we will share some of our key experiences with examples from the seven projects and provide a preview of some that are in preparation.
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Sequence stratigraphy and sedimentology of the Upper Jurassic Arab and Hith formations with emphasis on anhydrite deposits, Abu Dhabi, United Arab Emirates
The Kimmeridgian-Tithonian Arab and Hith formations are part of the highstand sequence set of a second-order supersequence, built by five third-order composite sequences (J70, J80, J90, J100, and J105) and bounded on top by sequence boundary J110_SB. The overall depositional environment envisaged for the Arab Formation is that of a barrier-shoal complex with open-marine, offshore sedimentation to the east and a protected, evaporitic, intra-shelf basin to the west. A barrier-shoal complex was developed along the platform margin and deposition was dominated by oolitic grainstones. Concomitant deposition of sabkha, tidal flat, salina and lagoonal sediments occurred westwards, and open-marine mudstones and wackestones were deposited eastwards of the
barrier-shoal complex. The reservoir quality is strongly controlled by the depositional environment and the lithofacies types. The best reservoir is present within grain-dominated lithofacies types of the barrier shoal complex. Relatively poor reservoir quality is characteristic of mud-dominated lithofacies types that occur in open-marine environments. In the intra-shelf basin the dominantly dolomitized lithofacies types show quite good reservoir qualities within thin intercalated packstone to grainstone layers, interpreted as tidal channels or washovers. During Hith time, the restriction of the intra-shelf basin increased and predominantly salinatype anhydrite after gypsum was deposited. The focus of this study is on the depositional environment of the anhydrite sediments, as it is important to distinguish between salina-type (saltern) and sabkha-type evaporites. In contrast to sabkha-type deposits, where the evaporites are forming within the host rock (sediment-dominated: late highstand and lowstand systems tracts), salina-type
deposits represent subaqueous evaporite precipitations (evaporite-dominated: late lowstand and transgressive systems tracts deposits). Distinguishing between the different anhydrite depositional environments is crucial for the correct sequence stratigraphic interpretation of the Arab and Hith carbonate-evaporite successions.
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Reservoir monitoring logging campaigns in offshore Abu Dhabi are handled with Collaborative Quality Value Assurance Project Management Approach
Monitoring of logging campaigns are conducted annually as part of reservoir management tasks. Such vital logging operations require the involvement of a multi-disciplinary subsurface team as well as that of the Support, Logistics and Field departments. Maintaining the communication and collaboration between team members is a key to success, which is measured in terms of knowledge transfer, best practices, process implementation and fast access to control the project phases. Moreover, reservoir requirements have to be transformed to logging programs and operational plans that have to be implemented successfully to assure high data quality acquisition. To assure this project’s annual success, the project team introduced a new approach named
(QMVA). This approach organizes the logging monitoring task into five phases. QMVA is an electronic program that runs on a personal computer. The program is connected to databases and accessible through a defined security system. After two years of utilizing QMVA it is clear that this project management and follow up has become much easier, faster and well-maintained. The success of having virtual team collaboration was achieved with continuous management support that realized the direct benefit
of this system. This presentation goes through all the stages of the QMVA system development and successful implementation.
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Integrating geological models, well data and geophysical methods in mapping the top salt interface over the stringer reservoirs
Authors Mohammed Al-Mazrui and Zuwena Al-Rawahi and Cees Van EdenThe Neopretorozoic carbonate reservoirs of the South
Oman Salt Basin are considered the oldest producing
reservoirs in the world. These carbonate stringer units,
fully encased in salt, form a unique hydrocarbon system
with proven economic viability. The greatest challenge in
exploring and producing hydrocarbons in these stringer
reservoirs, lies in the ability to confidently visualize them
and predict their properties. An additional challenge is
mapping the top of the salt. This impacts the time-todepth
conversion of the reservoir interval and hence the
geometry of the structure, which has direct bearing on
the calculated hydrocarbons-in-place. Over the years,
the top salt pick was solely made based on the seismic
data. Gravity data, which in general has a good lateral
resolution and poor vertical resolution, was mostly used
to validate this pick. This worked well in areas where
the top salt interface forms a strong reflector. This occurs
where the salt is overlain by a thick carbonate unit, or
in places where a significant impedance contrast exists
with the overlying conglomerates or sand of the Haima
pods. Integration of well and seismic data, using seismic
modelling and seismic-to-well ties, showed that mapping
the top salt depended on the ability to predict the lateral extent of the carbonate layer overlying the salt. By
combining the understanding of the seismic response.
together with a basic geological model of the extent of
the carbonate, facilitated capturing the uncertainties in
the top salt map.
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Early to late diagenetic dolomitization of a carbonate platform, Upper Jurassic gas reservoir, Mozduran Formation, Kopet-Dagh Basin, northeast Iran
More LessPlatform carbonates of the Upper Jurassic Mozduran Formation consist of widespread limestone and thick dolomite. The Mozduran dolomites comprise the main gas reservoir of the Kopet-Dagh Basin. However, inspite of their scientific and economic significance, the diagenetic origins of these rocks have been little studied. Reserves of about 500 billion cubic meters of gas were discovered in the Upper Jurassic and Lower Cretaceous sediments in the Khangiran field. Thick shale intervals and gypsum
provide good caprocks, and the hydrocarbon source rocks are believed to be the marlstones of the Middle Jurassic Chaman-Bid Formation. Petrographic, elemental and isotopic data indicated that the Mozduran dolomites were subjected to a complex diagenetic history, ranging from a wide spectrum of early-to-late diagenetic dolomitization. In this study, five varieties of dolomite have been recognized. Variations in dolomite types may reflect differences in formation time, formation mode, or the composition of the precursor limestone. The presence of higher concentrations of organic carbon (measured by Carlo Erba) in dolomites, compared to the limestones, may indicate that dolomitization was favored in those limestones that originally had higher concentrations of
organic matter. The preservation of a large amount of organic matter, which corresponds to relatively high δ13C values in the Mozduran dolomites, may be due to high rates of burial or dysaerobic (oxygen-deficient) conditions. The estimated maximum burial depth of the Mozduran Formation is about 4,0 km. Calculated temperatures from stable, oxygen-isotope compositions of late diagenetic dolomites suggest that these dolomites formed between burial depths of c. 3.5 and 4.5 km. According to the paleotemperature analysis, gas traps were formed during the Late Alpine Orogeny (about 10 Ma).
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Impact of results from complex data-intensive wells on understanding fault, fracture and clinoform geometry: Examples from a maturing carbonate oil field in Abu Dhabi, United Arab Emirates
More LessIn an effort to accelerate field redevelopment, opportunities have been identified to re-activate wells through horizontal sidetracks and acquire geological data to evaluate potential discontinuities, irregular water front advance and uneven pressure distribution. The studied reservoir has been producing mainly from the south of the field, from platform interior and margin deposits. The north of the field is complicated by the presence of clinoforms and common faulting. Progradational clinoform belts in the north show rapid alternations of reservoir properties. Lack of crestal pressure support and uneven waterfront advance confirmed high reservoir complexity, with the main uncertainties being: (1) up-dip extension of barriers (dense limestone) related to third- and fourth-order
transgressions within clinoforms; (2) continuity and sealing capacity of NW-trending faults; (3) connectivity between poorer quality clinoform bottomsets and the topsets of unit 1; (4) NS-trending discontinuities impacting pressure dissipation from flank-to-crest; and (5) detection and characterization of fractures (spatial extent, orientation and transmissibility). Recent drilled wells have included: (1) pilot holes with cores, borehole image logs and pressure/fluid measurements to evaluate the up-dip extension of dense units within clinoforms; (2) horizontal drains crossing several clinoforms and faults aimed at resolving complex structural and sedimentary geometries (distance to boundary logging and borehole imaging); and (3) borehole image logging in pilot holes and horizontal sections to characterize facies, fault and fracture distribution The integration of results from these wells with complementary studies (e.g. seismic attribute analysis, sequence stratigraphy, core studies, dynamic modelling) forms the foundation for optimizing the development scheme, extending field plateau life, and maximizing recovery.
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Geology and rock properties correlation: Outcrop analogue study of a Cretaceous reservoir, United Arab Emirates
Authors Hamdan Al-Menhali, Sandra Vega and Mohammed Ali and Manhal SiratGeological and petrophysical investigation has been performed in an outcrop located at the northeast of Ras Al Khaimah, where Lower Cretaceous rocks of the Thamama Group dip gently into the subsurface. The area is of stratigraphic significance because it can be used as an analogue model for the Thamama reservoirs of the United Arab Emirates. The aim of this study is to better characterize and correlate the geology and rock properties of the exposed rock, and use it as an analogue for Thamama Group. This work combined the results of the following methodologies: (1) geological analysis, which included description, stratigraphic column and mapping of the outcrop; (2) rock properties analysis, which included porosity, permeability, porosity type, and mineralogy
of 17 outcrop samples; and finally (3) correlation between outcrop and reservoir field properties. Our preliminary results indicated that the studied outcrop consists of mudstone-wackestone that has been crystallized with no major lateral changes. Seven main lithological units have been recognized on the basis of their depositional and/or horizontal continuous fractures. In addition, the outcrop samples display a considerable number of vertical joints filled with calcite. Horizontal open fractures are clearly present, which affect permeability. Few units have small burrows (1.0–2.0 mm) that slightly increase the porosity. Some of the lower and intermediate units contain relatively high concentrations of iron, which reduces resistivity. Finally, our observations showed that,
in contrast with the subsurface Thamama reservoirs, the exposed units have very low porosity as a result of local cementation.
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Seismic data tracking and recovery in the exploration effort: The Seismic data TREE
More Less2-D and 3-D seismic data undergo various processing and interpretation stages within the exploration workflow. To track down the effort that was invested in every seismic line or survey is an immense challenge. The aim of this study is to find a method of tracking and recovering all the effort that was invested on seismic data, whether in acquisition, processing or interpretation. The new proposed method manages both data and knowledge to maintain a seismic Tracking and Recovery within Exploration Effort (Seismic TREE). The proposed process enhancement technique is based on the LEAN processing enhancement technique. Lean manufacturing is a generic process management philosophy derived mostly from the Toyota Production System but also from other sources. It is renowned for its focus on reduction of the original Toyota ‘seven wastes’ in order to improve overall customer value. The LEAN method is often linked with Six Sigma because of that methodology’s emphasis on reduction of process variation. Using the LEAN method, we minimized the waste as well as captured all varieties of seismic data for knowledge management purposes.
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Organic geochemical indications for source potential and hydrocarbon generation from Late Jurassic-Early Cretaceous Sulaiy Formation, southern Iraq
Authors Furat A. Al Musawi and Thamer K. Al AmeriThis presentation describes an organic geochemical analysis of the Late Jurassic and Early Cretaceous (Tithonian to Valanginian) Sulaiy Formation in the Basrah region in southern Iraq. Samples from six wells were used to analyze thermal maturation and measure sedimentary organic matter parameters. The analyses included quantitative studies such as elemental analysis, pyrolysis, fluorescence spectroscopy (ultra-violet) and total organic carbon (TOC). Additionally, qualitative studies involved textural microscopy that was used in evaluating amorphous organic matter for palynofacies analysis leading to hydrocarbon assessments. The Sulaiy Formation was rated as a source rock for oil with some gas because of its high TOC content and mature organic matter. The kerogen is type II of mesoliptinic type. The Sulaiy Formation is also recognized as a source rock, not only in Iraq, but also in neighboring Kuwait and Saudi Arabia.
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Using GPR and resistivity methods to detect subsurface karst cavities
Authors Khaled F. Al-Mutairi and Nasser S. Al-ArifiGround penetrating radar (GPR) and resistivity methods were used to detect the subsurface karst cavities in Jubaila Formation, west of Riyadh, Saudi Arabia, These features may cause geological or environmental hazards to buildings and constructions. The aims of this study are to understand the physical properties of subsurface cavities, the response of the formation structure to these geophysical techniques and to evaluate them in geotechnical and engineering studies. By 250 MHz frequency, GPR was found to be clearly effective in detecting variations of the electrical properties of shallow subsurface structure up to a depth of 6 m, and to 8 m with lower resolution. The GPR images detected strong and continuous reflections from horizontal layers with similar
positions and depths (at a depth 4.75 m), which have an electrical resistivity value between 180–300 ohm-meter. The GPR sections did not detect any caves in the layers; i.e. the caves are not continuous nor extensive, but rather showed a homogenous structure in the lower section. The GPR results were improved-upon by the electrical resistivity method. This method detected the horizontal layers, which in parts showed zoning of the resistivity. The zones show a distributed field with a semi-circular gradient and a sharp value in the center. Based on drilling, the central point was found to be a limestone layer with facies change, hardness or indurations. The resistivity of the central point reached 280 ohm-meter, while the surrounding media’s resistivity is 120 ohm-meter. The results of GPR and resistivity methods are supported with geotechnical drilling, which were in agreement with the interpretation.
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The new exploration challenge: Finding the basin center resources
More LessUnconventionally trapped oil and gas will play an important role in meeting the world’s thirst for hydrocarbon products in the next few decades. Basin center gas (BCG) accumulations are one of the important economic unconventional hydrocarbon plays that is known to exist in many basins of the world. It is also referred to as tight gas sand, deep basin gas, and continuous gas accumulation. It has been the subject of exploration and production for the last three decades in the United States and Canada. Thousands of wells have been drilled and geologic models for this resource, which promises to be vast, have been established. Generally, basin center gas is characterized as being a regionally extended accumulation of gas that is not conventionally trapped, abnormally pressured (high or low), commonly lacks a down-dip water contact, and has low-permeability reservoirs. The accumulation ranges from single, isolated reservoirs, a few feet thick, to multiple stacked reservoirs that are several thousand feet thick. To find and exploit these resources, many challenges have to be addressed. These challenges include geological, geophysical, drilling and completion techniques. In immature basins, such as the Arabian basin, the exploration for basin center gas requires a shift in exploration thinking that may impact the data acquisition, processing, and interpretation methods. Under these conditions, technology plays a major role in optimizing the exploration results.
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Managing water in mature fields for increased recovery
Authors Mazen Al Omari and Jørgen HallundbækWell management is a continual exercise in optimizing the yield of the system and to evaluate the potential of initiating measures that can increase production. The management of produced water occupies a priority area in the oil and gas industry as water severely complicates production, and sometimes even makes it non-profitable. Based on an estimate, approximately 250 million barrels of water is produced every day worldwide. Furthermore, the water-to-oil ratio increases over the life of a well, which means that mature wells produce up to 9.5 barrels of water for each barrel of oil. Some wells produce at a water cut above 90%; a number that often cause operators to abandon wells instead of pursuing interventions. These factors make it imperative to develop
and apply the right technology to handle the large amounts of produced water. Tractoring on wireline has proven to be an efficient method for managing water in horizontal and highly deviated wells. With this technology, a series of attractive possibilities are unlocked: (1) enhanced production; (2) greater recoverable reserves; (3) prolonged lifespan of mature fields for more profitability; (4) reduced gas-to-oil ratio; (5) environmentally-responsible handling of produced water; and (6) increased safety on job. A solid track-record of applying tractor technology on wireline has already been established. With reliable results, mechanical down-hole solutions on wireline are capable of managing the flow control while providing certainty of execution and keyhole precision in water management. Additionally, these services mean large cost reductions and value-creation as will be illustrated in this presentation.
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Dolomitization and reservoir characterization of the Cretaceous Qamchuqa Group, Khabaz oil field, Kirkuk area, northern Iraq
More LessThe Lower Cretaceous (Aptian-Albian) Qamchuqa Formation, in the Kirkuk area of northern Iraq, consists of thick shelf carbonates. It is here recommended that it be raised to a group status consisting of three formations; the upper and lower Qamchuqa formations that are separated by the Sarmord Formation. The upper and lower Qamchuqa formations were deposited as platform carbonates in a wide spectrum of shelf subenvironments, whereas the Sarmord Formation consists of basinal facies. Pervasive dolomitization affected the Qamchuqa formations and their reservoir properties. This study examined cuttings, cores, and different types of wireline logs, as well as production data from seven wells in the Khabaz oil field. The analysis revealed important links
between sedimentary facies, dolomitization, eustatic fluctuation and the heterogeneity of reservoir rocks. A wide range of dolomite fabrics were identified including microcrystalline, planar-e, planar-s, planar-c, planar-p, as well as saddle and non-planar types. These imply successive phases of dolomitization, which profoundly influenced the enhancement of reservoir character. Intercrystalline microvuggy, and micromouldic porosity are the most important products of this dolomitization. Fracturing and the retained primary sedimentary fabric of the undolomitized, or partly dolomitized, facies contributes to the collective porosity and permeability of the reservoir. Linking these modes of dolomitization to the eustatic cycles of the sequence shows that part of the intensively dolomitized sections are associated with highstand episodes.
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Estimating static shifts by deconvolving stacking velocity profiles
More LessSeismic exploration aims to provide high-quality data in order to optimize finding hydrocarbon reserves and to minimize drilling costs. However, for land seismic data, near-surface irregularities act as a noise generator and create static problems, which can considerably degrade seismic images. We have investigated a potential and unconventional approach to extract static shifts from seismic data. This approach extracts time delays, generated by near-surface irregularities, from a stacking velocity profile for a given seismic reflector. This is accomplished by deconvolving the stacking velocity profile with the impulse response of the seismic acquisition spread. The impulse response is basically the stacking velocity profile due to the interaction between the acquisition
spread and a single near-surface impulse time delay. We applied the method on a synthetic model that consisted of five horizontal layers and three near-surface irregularities. The lateral extents of the irregularities are equal to the full, half, and one-quarter of the spread length, which was 1,500 m. The time delays corresponding to the three near-surface irregularities were held constant at 8.0 millisecond. The stacking velocity profile from the third interface was hand-picked and showed high oscillations under the near-surface irregularities. This picked stacking velocity profile was deconvolved by the impulse response to estimate the time delays that caused the oscillations. The errors in the estimated time delays were consistently less than 10%, which demonstrates the
ability of the proposed method to recover time delays from stacking velocity profiles.
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