Improving seismic data quality prior to acoustic impedance (AI) inversion is one of the main challenges for interpreters. Proper reprocessing of seismic data may attenuate most of the noise and multiples but it can be costly and time-consuming. Therefore, while data reprocessing is in-progress, an interim solution is implemented to enhance 3D seismic quality. The solution was an effective data conditioning workflow that significantly improved seismic quality for satisfactory inversion results. Having achieved acceptable seismic data quality, we inverted the seismic volume to estimate acoustic impedance. A seismic porosity model is transformed from this acoustic impedance and used for reservoir heterogeneity prediction and well placement. The analysis indicates that the wavelet equalization is a very useful tool for stabilizing the wavelet phase and amplitude spectrum in the study area. To ensure stability of the seismic wavelet at well locations, wavelet extraction is performed before and after wavelet equalization. The structural and stratigraphic interpretation is significantly improved by inverting the conditioned seismic data to relative acoustic impedance (RAI). The acoustic impedance estimates is validated by comparing them with well log values. This validation is essential to quantify the depth conversion and to provide optimum guidelines for drilling/geo-steering. Therefore, the final acoustic impedance inversion is showed good correlation with well log data. The inversion results are successfully used to position new horizontal wells in the study area. Our experience revealed the importance of acoustic impedance inversion in guiding geo-steering wells, particularly in heterogeneous reservoirs. However, the limitation of vertical seismic resolution remains the main challenge. The study provides best practice of seismic data optimization by stabilizing wavelet phase before inversion. Ultimately this improved our ability to position horizontal wells in heterogeneous reservoirs.
The study area is located eastern Saudi Arabia (Fig. 1) and surrounding by three separate intra-shelf basins (Sharland et al., 2001): (1) Gotnia Basin, (2) Arabian Basin, and (3) Rub Al Khali Basin. The evaluation of existing seismic data revealed many issues such as random noise, inconsistency of wavelet phase and amplitude spectrum. Moreover, inadequacy of the applied static correction is another issue that observed from field operations. Unstable amplitudes across the study area from north to the south are obviously observed in the previous acoustic impedance inversion results.
Khurshid, Ilyas (UAE University Al-Ain UAE) | Hossain, Md Monwar (UAE University Al-Ain UAE) | Alraeesi, Abdulrahman (UAE University Al-Ain UAE) | Fares, Ameera (UAE University Al-Ain UAE) | Albalushi, Fatima (UAE University Al-Ain UAE) | Alhammadi, Amina (UAE University Al-Ain UAE)
Produced water is the largest waste stream generated in oil and gas industries. It is a mixture of different organic and inorganic compounds. Global produced water production is estimated at around 280 million barrels per day compared with around 97 million barrels per day of oil. As a result, water to oil ratio is around 3:1 that is to say; water cut is 70%. Due to the increasing volume of waste all over the world in the current decade, the outcome and effect of discharging produced water on the environment has lately become a significant issue of concern. In certain fields like Asab oil field Abu Dhabi UAE, the produced water is re-injected in the field through injection wells. However, it is found that the concentration of salt in injected formation water in Asab field is 150,000-262,000 ppm and this high saline water is injected in the reservoir. Where it may cause severe formation damage: pore plugging, water injectivity and oil productivity problems. Our objective is to develop a cost effective technique to reduce the salinity of this produced water to control formation damage.
We used a couple of chemicals/reagents to reduce the salinity of injected water in Asab field, to increase oil recovery and minimize formation damage such physico-chemical and/or pore blockage. This research examines the sources, characteristics, and extent of different chemicals specially fatty acids and different other techniques that can be used to reduce the salinity of water because no single technology can meet suitable effluent characteristics, thus two or more treatment systems might be used in series operation. However, we were successful to reduce the salinity of brine to approximately 64-74%, where it can be re-injected into the reservoir with minimum formation damage and maximum injectivity.
Schedule Session Details Expand All Collapse All Filter By Date All Dates Sunday, April 15 Monday, April 16 Tuesday, April 17 Wednesday, April 18 Filter By Session Type All Sessions General Activities Social and Networking Events Technical Sessions Panel, Plenary, and Special Sessions Training Course/Seminar Sunday, April 15 08:00 - 17:00 Seminar: The Sustainability Imperative - Making the Case and Driving Change Ticketed Event Instructor(s) Johana Dunlop, SPE Board Member and SPE HSE Technical Director, Affiliate-Schlumberger Professional Societies Program; Linda Batallora, Teaching Professor, Petroleum Engineering, Colorado School of Mines The objective of this course is to provide participants with tools, techniques, and knowledge for immediate use to help operators maintain project value through sustainability. A fundamental principle underpins this course: securing and maintaining license to operate (as well as growing the commercial value beyond this minimum threshold) extends well beyond legislative requirements and regulatory permitting. It encompasses not only the mitigation of adverse social and environmental impacts but also the advancement of financial, societal, and environmental benefits via the execution of strong sustainability performance. Cost: SPE Member USD 787.50 Nonmember USD 945 Register Now ► 08:00 - 17:00 Seminar: Process Safety for E&P Operations Ticketed Event Instructor(s) Mark Hansen, Past-President and Fellow, American Society of Safety Engineers (ASSE) and Founder and Chairman, Business of Safety Committee This course provides a fundamental understanding of process safety techniques and how applying these techniques can improve safety, equipment reliability, environmental performance and reduce overall costs. It presents an overview of the elements comprising process safety, practical examples and how process safety can be integrated into day-to-day operations.
Periere, Matthieu Deville de (Badley Ashton and Associates Ltd.) | Foote, Alexander (Badley Ashton and Associates Ltd.) | Bertouche, Meriem (Badley Ashton and Associates Ltd.) | Shah, Razza (Al Hosn Gas.) | al-Darmaki, Fatima (Al Hosn Gas.) | Ishaq, Wala bin (Al Hosn Gas.)
The Lower Arab D Member (Kimmeridgian) in onshore UAE is typically characterised by a thick succession of homogeneous mudstones with local cm-scale interbedded bivalve-rich floatstones, which are thought to have been deposited in a low-energy mid-ramp setting. This sedimentological unit is located at the base of a sour gas reservoir that includes the oolitic grainstones of the Upper Arab D Member. The pore system in these micritic deposits is dominated by matrix-hosted microporosity, along with open to partially cemented fractures, primary intraparticle macropores and rare biomoulds in the shell beds, hence a poor to very good porosity and extremely poor to rarely excellent permeability. Variations in porosity and permeability values appear to be strongly related to variations in the micritic fabric: both porosity and permeability increase when the micritic fabric evolves from anhedral compact with coalescent intercrystalline contacts (associated with very little and poorly connected micropores) to subrounded with facial to subpunctic intercrystalline contacts (with locally well-developed micropores). Micritic fabrics also clearly impact the elastic properties of the rock. Through analysis of elastic moduli calculated from standard density, and shear/compressional sonic wireline logs, the relationship between micritic fabric, porosity, permeability and geomechanical properties has been explored.
The aim of this study is to propose a stratigraphic and sedimentary framework though the integration of available sedimentary, diagenetic and petrophysical data, which will be utilized in the construction of a high resolution stratigraphic framework, as an input into comprehensive review and update of an existing model of heterogeneous carbonate reservoir in a mature field in Abu Dhabi, UAE.
Depositional facies have been defined in cored wells, subsequently were associated taking into account the biologic and sedimentary processes in response of carbonate growing and sea level changes, allowing the identification of the main stratigraphic surfaces.
Surfaces can extend the correlation along the field and define the model of facies that, with the evidence provided by cores, can recreate and predict the different regressive-transgressive cycles in high resolution which the carbonate platform were undergone during its evolution.
Diagenetic evolution, interpreted through laboratory observations, was integrated with facies and petrophysical evaluation allowing the understanding of the spatial distribution of petrophysical properties within a heterogeneous reservoir and define a new set of facies which will be used in the generation of geological static model.
Application of sequence stratigraphy methods in cores, and extended in logs allowed the identification of six depositional sequences, with thicknesses of 2 to 4 meters each, corresponding to the phases of carbonate platform growth. Within each depositional sequences, typical cycles were defined that support the understanding in the association of facies and their relationship during the deposition.
The identification of sedimentological cycles not only genetically organizes the facies and predicts the stacking pattern, but also makes possible to find an excellent correspondence between cycles from lowstand system track intervals with good to excellent permeability values, and cycles from transgressive system track intervals with low permeabilities.
Many of the sequence stratigraphy published articles driven for the most important reservoirs along the Arabian Plate, provide an excellent tool in the regional correlation. However, they are not enough to be used in the reservoir characterization in detail that is required during the development of the field neither as input data in the generation of geological static models that use the sedimentary trends as constrain to populate the petrophysical properties.
Abu Dhabi fields are influenced by strike-slip and their damage zones as a main tectonic regime. A damage zone is the deformed volume of rocks around a fault surface that results from the initiation, propagation, interaction, and build-up of slip along fault segments. These damages zones impacted the distribution of the traps, migration pathways and increasing the drilling risks. Slippage and rotation along the fault segments in Abu Dhabi fields increases the damage zones widths around the fault segments. This paper presents a detailed description of the kinematics and dynamics of rotated damage zones in the strike-slip faults of Abu Dhabi fields.
The factors that are controlling the damage zones around faults are mainly the rock type, relation between bedding and fault plane and stress tensors. This paper, however, focuses on the structures within the damage zones as they are influencing the trapping mechanism, the drilling hazards and how the rotation increases these. In addition, the structures formed at the fault tips are also considered, especially for the initiation and propagation of the fractures. Field examples and outcrop analogues of damage zones around strike-slip faults are presented. This study is integration between seismic, cores, logs, and outcrops.
During the Late Cretaceous the kinematics of Abu Dhabi fault system changed to transtensional and accommodated a major component of left-lateral strike-slip motion with a SE-NW compressional component. The final phase occurred by the Miocene time, where the stress tensor is changed to NE-SW compression, which rotated the blocks. During this deformation, the blocks were dissected into a series of large-scale blocks bounded by NW-trending left-lateral strike-slip faults which merge into a NE–SW fault system that forms the main structures in Abu Dhabi. Field studies on the mountains exposures data from the fault bound subsurface blocks indicate 10°–15° of post-Early Miocene anticlockwise rotation with substantial latitudinal motion.
The decrease/increase of stresses along the fault segments in the overlapping/linkage zones and at the fault tips under differential confining pressures affecting the rocks behavior and understanding of these will greatly avoid drilling dry holes and reduce the drilling risks.
Regional aquifers are critical for development of oil/gas fields that need water injection for pressure maintenance. However, modeling of regional aquifer is a difficult task as data acquisition and analyses are primarily focused on hydrocarbon bearing intervals. Also, aquifers are generally regional, whereas the data available is clustered around oil/gas fields with negligible data in the vast areas lying outside the fields of interest. The present study aims at building a regional aquifer model for Abu Dhabi Onshore area integrating all the available data in different scales that may be used in planning future availability of water resources.
Most of the oil/gas fields located in Onshore of Abu Dhabi have so far been developed by primary pressure maintenance strategy injecting water obtained from the shallower Late Cretaceous, Paleocene and Eocene aquifers. The main water source reservoirs are Dammam, Umm Er Radhuma and Simsima formations. Despite limited data availability, the study delivered a fit for purpose 3D reservoir model integrating seismic data, regional outcrop analogs and available log and core data. An enormous database containing 4768 wells from 10 most important Fields of onshore Abu Dhabi was used to build the structural framework with the help of regional seismic interpreted surface. Sequence stratigraphic cycles were identified in all the formations considering eustatic curves and correlation using GR-NPHI-RHOB logs. Average layer thickness was designed to be around 20ft in all the reservoir intervals. Input for property model was very limited as logs and cores are generally not acquired in aquifer intervals. Wells with NPHI-RHOB logs were used for estimation of porosity and it was calibrated with limited core porosity data available. Permeability has been computed by fitting functions to Poro-Perm cross-plot and then adding statistical dispersion based on observed core permeability data. Different scenarios of permeability were defined due to the high dispersion in the core data. For dynamic modelling three equilibration regions were setup for the main three aquifers and a common PVT table was used. All the water supply and disposal wells were used in history matching. The high case of permeability was found to honor best the production and injection data.
The static model built integrating all available data in different scales is robust. Although limited data availability for property modelling was a major concern, the model did show reasonable history match and is fit for purpose to predict future water supply. A systematic data acquisition plan for these aquifers may be implemented in future to make the current model more reliable.
The regional aquifer model of Abu Dhabi Onshore is the first of its kind in the country that incorporates all the available information including seismic interpretation in regional scale to small-scale core data.
Wettability influences the flow motion of hydrocarbons in carbonate oil reservoirs: it is measured in laboratory with specific procedures including assessment of its initial value. Conventional or special core analysis requires good cleaning of the cores. Additional measurements like relative permeability or capillary pressure for instance require restoration of the initial wettability conditions of cores by aging them. The routine methods for assessment of wettability are USBM and Amott-Harvey (A-H) tests, which involve large amount of efforts and time. In this study we replace these tedious processes by tracking the aging through repeated NMR and resistivity measurements.
Four core plugs, two dolomites and two limestones, were selected from twenty carbonate plugs collected from different outcrops. After saturating the samples with brine, the cementation factor m was calculated. NMR T2 relaxation was performed as a reference on fully brine saturated samples. Crude oil was injected into the plugs until they attained Swi. An NMR T2 was measured on them before aging. Then one limestone and one dolomite were immersed in crude oil and placed in an oven at reservoir temperature, while the two other samples were loaded in resistivity core holders under same reservoir temperature and confining pressure to age them. Resistivity was measured continuously while NMR T2 were recorded at different time intervals to observe the response of the aging core samples to independent physical investigations.
The NMR and resistivity measurements were used to identify the wettability alteration. The resistivity change showed a continuous wettability change in the plugs, which was also confirmed by the continuous change in the NMR T2 response. Both methods showed that dolomite was more prone to becoming oil-wet than limestone. It was verified by USBM and Amott-Harvey tests on same plugs. Further tests will be necessary to validate the generality of the overall workflow.
Al-Thuwaini, Jamal (Lukoil Saudi Arabia Energy Ltd) | Abdulaziz, Mohammed Emad (LUKSAR) | Ekpe, Joseph (Lukoil Saudi Arabia Energy Ltd) | Jaffery, Maimoon Fayyaz (Schlumberger) | Ong, Lee Sing (Schlumberger) | Taoutaou, Salim (Schlumberger) | Ahmad, Bilal (Schlumberger IPM-RMG)
Zonal isolation has extreme significance in the construction quality and life of a well. Achieving zonal isolation in deep highpressure, high-temperature (HPHT) gas wells is a challenging task, and these wells need more attention to achieve zonal isolation than conventional oil or gas wells. In addition to following primary industry best practices, the selection of a cement system appropriate for the environment of the well is very significant. Trapped gas and oil between production and intermediate casing (abnormal annulus wellhead pressure) has been globally recognized as one of the serious challenges facing drilling and production operations. The issue is becoming even more serious since wells are aging and the integrity of the casing portion below the well head is increasingly affected by the shallow-water corrosive environment. The potential safety and environmental hazards of the abnormal annulus pressure, have encouraged LUKSAR (Lukoil Saudi Arabia Energy Limited) to review the current drilling and cementing practices, with the goal of minimizing the impact of the problem, thus improving well life cycle and reducing the frequent work-over interventions. The general guidelines set to resolve the problem focused on eliminating potential leakage paths in the completion and casing strings and emphasized the quality of the primary cementing, especially for casings set on the aquifer zones and production casings.
This paper discusses case histories and selection criteria for the different cement systems. It shows how high-performance lightweight sealant across weak zones, fiber-based sealant technology when lost circulation prevails, self healing sealant system where zonal isolation is extremely important, and flexible and expanding sealant for frac candidates are chosen for providing and maintaining well integrity in these extremely remote and challenging HPHT wells.
LUKSAR is drilling HPHT wells in the Rub Al-Khali basin in Saudi Arabia. The basin underlies a sand desert by the same name, which covers an area of about 804,670 km2 (310,685 mi2). It extends from the eastern edge of the Arabian Shield to the Oman border on the east, and from the Central Arabian Arch in the north to the Hadramout Arch in the south (Fig. 1).
A generally accepted definition of an HPHT well is described as one in which "the undisturbed bottomhole temperature at prospective reservoir depth or total depth is greater than 300°F (149°C), and either the maximum anticipated pore pressure of any porous formation to be drilled exceeds a hydrostatic pressure gradient of 0.8 psi/ft (97 Pa/m), or pressure control equipment with a rated working pressure in excess of 68.94 MPa (10,000 psi) is required. Many of the key reservoirs in the Rub Al-Khali meet this definition (Fig. 2). High pressure could be encountered in the Jilh Dolomite, Khuff and Unayzah formations (Fig. 3). Typical reservoirs are the Unayzah, Qasim and Sara. These sandstone reservoirs are defined as gasbearing formations. Temperature gradient in the Qasim and Sara formations ranges from 2.2 to 2.4°C /100 m (1.2 to 1.3°F/100 ft). Most wells drilled into these sands do not flow because of very tight formations with very low permeability. These formations are fractured with high pressure to make them flow.
Another significant drilling challenge in Rub Al-Khali HPHT wells is the insufficient borehole pressure integrity, especially when drilling through the naturally fractured limestone of the Wasia, Um Er Radhuma (UER), and Shu'aiba formations. Lost circulation of drilling fluid occurs, and loss rate can go from partial to total loss. Generally, the aforementioned formations are drilled with the mud-cap method in the case of total lost circulation.
Al-Thuwaini, Jamal (LUKSAR) | Abdulaziz, Mohammed Emad (LUKSAR) | Ekpe, Joseph (Lukoil Saudi Arabia Energy Ltd) | Jaffery, Maimoon Fayyaz (Schlumberger) | Ong, Dominic (Schlumberger) | Bermudez, Raul (Schlumberger) | Taoutaou, Salim (Schlumberger) | Ahmad, Bilal (Schlumberger IPM-RMG)
Long-term zonal isolation is an important factor to consider while designing cement slurries for deep high-pressure, high-temperature (HPHT) gas wells. Conventional heavyweight cement systems used in the past have often had to sacrifice set cement mechanical properties, such as compressive strength, permeability, and porosity, to provide a stable, mixable, and pumpable slurry design.
Changes in downhole conditions in terms of temperature and pressure can induce sufficient stresses to destroy the integrity of the cement sheath, causing long-term gas migration and sustained annular pressure. Hence, the set cement mechanical properties have to be carefully designed in order to withstand the downhole stresses, especially the ones generated from well testing.
A novel flexible and expanding cement system was chosen for the eighth well of project in Saudi Arabia.