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.
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.
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.
Horizontal wells have become very common in the Middle East because of their capability to increase reservoir contact, particularly in carbonate reservoirs. These types of formations often are naturally fractured, and because of channeling from underlying aquifers, allow the ingress of water into the production process systems. When water breaks through to the well completion, it tends to increase and becomes preferentially produced, thereby reducing the volume of produced hydrocarbons. This phenomenon adds cost to the well operation because of the requirement to lift, separate, treat and dispose of the water. Preventing and managing water-cut through cementing, chemical application or the use of mechanical openhole barriers such as inflatable packers is costly, and often, the method chosen is not effective.
This paper will discuss the use of swellable packers to provide a long-term, completely effective, water shutoff tool. These packers use expanding rubber around the packer that expands to seal the annulus. When expanded, a permanent seal is created, regardless of whether the packer has been run as a straddle or as a plug. The packers can be used in open and cased-hole applications in all the most common oil- and gas-well environments.
This paper discusses the development and design of the packer and presents case histories from the Middle East and other parts of the world that illustrate the advantages that swellable packer technology can provide to operators in reservoirs in which water break-through has been predicted or experienced.
In these case histories, it will be shown that the packers significantly reduced water cut, which in turn, reduced water disposal costs and intervention needs while increasing production rates and extending field life.
Major oil companies worldwide continue to evaluate new technologies to ensure that their strategic resources are optimally explored, developed, and efficiently produced during the life of their oil and gas fields. Abu Dhabi National Oil Company (ADNOC) along with its group of subsidiary companies are among the companies that continue to pursue innovative technologies. The actual adopting of a new technology varies considerably between different operating companies with the early adopters being more willing to take risks if it means that the investigated methodologies could prove to offer greater advantages to production scenarios. Since the swellable packer has shown success in many different applications, its acceptance has been accelerated. The exponential growth in usage of the swellable packer is shown in Figure 1.
Management of produced water has been a major challenge in the ADNOC and other operator wells in much of the Middle Eastern area. Water cut in new and existing production wells is undesirable, and in many cases, leads to increased operating costs to dispose of the water, expensive remedial treatments, environmental issues related to disposal, and the premature shut in of the wells. This often leaves oil in place that may never be produced.
In the last twenty years, step changes in the capability to deliver accurately placed long horizontals have proven extremely beneficial to many operators of carbonate reservoirs worldwide. Natural and drilling-based faulting and fractures in these formations are relatively common, and water from other nearby formations will use these channels to break through to the production string, significantly reducing oil production. Operators worldwide have used multiple technologies to try strategies that can combat "bad?? water; i.e., water that does not add to net oil produced. Chemical methods have proven effective in targeting longer sections where the gels and polymers can be placed deeper into the formations. Fractures and faults typically have been targeted with mechanical isolation methods such as bridge plugs and inflatable packers.
This paper discusses a newly developed technology, swellable packers, and uses case histories from the Middle East and other regions to describe their use to improve the reliability and deployment of mechanical water shutoff methods.
The Ghawar field in Eastern Saudi Arabia contains the largest accumulation of carbonate reservoirs in the world. The majority of wells in the field produce from the Arab-D reservoir, an Upper Jurassic limestone sealed by anhydrite. Oil production from the field started approximately 55 years ago. Water injection started in the 1970's. Long before water injection was considered for the reservoir, the evaluation of wettability was considered essential.
Our present day evaluation of Arab-D wettability takes into account a long historical record of wettability measurements and production history. The procedures, results and caveats of the original measurements have changed slightly but they also show a strong consistency fifty years later. Wettability indices obtained from initial tests, Amott, and USBM methods generally indicate neutral to slightly oil-wet character for cores processed and tested in a preserved state. Comparisons with restored state cores did not indicate major differences. Over the years fluids used in coring operations and core preservation have shown little impact on the observed results.
Local variations in wettability indicating mixed wettability and oil-wet tendencies can be observed when tar is present in a significant amount and in areas high on structure. The combination of methods from advanced SEM observations, to qualitative contact angle measurements, to relative permeability results all point to a common wettability value.
Recent mapping of fault patterns from picked surface attribute analysis (‘difference' maps, spectral decomposition, isochron maps) and time slices over a giant offshore field in Abu Dhabi has recognized a complex multi-set pattern of faults at reservoir level. As well as providing additional seismic scale faults, linear features (proposed subseismic faults and fracture systems) have been identified.These patterns are best described in terms of strike-slip geometries; however, many display components of both dip-slip and strike-slip over their movement history.In different parts of the field dominant fault directions displaying dextral transtension, dextral transpression, trapdoor hinge faulting and oblique-slip keystone graben generation are observed.Fault throw statistics and segment growth history in the most important mapped zones typify components of strike-slip along with local shear and segment termination at cross-fault zones. The prevalent fault trends are roughly orthogonal NE-SW and NW-SE systems that dissect the field. Superimposed on this geometry is an array of distinctly en-echelon WNW-ESE and WSW-ENE structures that link to steep zones at deeper levels.Within sub-regions of the field other trends are also present, including NNE-NNW to N-S, NNW-SSE and E-W. These sets do not form a radial pattern; they are distributed spatially within field domains and involve complex systems and layer-related rheologically controlled deformation.
Comparison of the mapped lineament pattern with core-derived fracture orientation data shows that all sets identified in the field from seismic are present within the overall fracture strike system within the wells. Field-wide, domains where transtension and transpression dominate, as well as more dip-slip dominated areas can be mapped out. Core scale fractures tend to display a component of strike-slip within the bulk strain field-wide, as evidenced by steep or sub-vertical fracture intersections. Newly identified lineament zones allow better understanding of high intensity fractured wells previously mapped distal to known faults
Results and discussions in this paper relate to a Lower Cretaceous carbonate reservoir located in southeastern Saudi Arabia. It is a heterogeneous carbonate formation with various facies due to diagenetic alteration of the original rock fabric. The reservoir is large and prolific with mixed-wet characteristics. Because of the economic importance and variety of oil-recovery mechanisms operative or possible in the reservoir, the multi-phase recovery behavior has been extensively studied. Also, various wettability tests were carried out using Amott and USBM methods.
This paper describes the variation in wettability and relative permeability of Lower Cretaceous carbonate reservoir and the multi-phase simulations of the experimental results. It shows that measurements are consistent with recent theories of the relationship between water saturation, relative permeability, and wettability as described by Jadhunadan and Morrow, 1991.1 However, the results indicate that the wettability of the reservoir changes from water-wet low on structure near the oil/water contact to intermediate and/or oil-wet behavior higher on structure. Oil-wetting character increases towards the top of oil column and is correlated to decreasing water saturation. The results revealed that changes in wettability are accompanied by changes in waterflood efficiency and facies of deposition.
Development trials of peripheral horizontal injectors were performed in an attempt to establish waterflood sweep within the low permeability lower half of a Thamama reservoir. This paper describes the performance of the horizontal injectors, as well as a time lapse formation tester interference test between a horizontal injector and open hole observation well, spaced 100 meter apart. The test was designed to measure the distance it takes water from the horizontal injector to break through into the high permeability upper half of the reservoir.
Interpretation of the results show that water from horizontal injectors moves vertically out of zone within 100 meters of the injection point, and is not contained within the lower half of the reservoir. Full field simulation after history matching the interference test results shows small increase in vertical and areal sweep efficiency resulting from utilization of horizontal injectors. Radioactive tracer injected into a horizontal injector in the lower part of the reservoir migrated upward into the upper part and traveled up dip 1km to an observation well within 3 years, traveling more than 3 feet per day.
While use of horizontal producers has been identified as the primary method for increasing recovery from the lower part of this Thamama reservoir, the benefits of horizontal injectors over vertical injectors is small. Horizontal injectors can only be justified when costs of adding a horizontal tail to a newly drilled injector is equally small. High recompletion costs of converting existing peripheral vertical injectors to horizontal injectors through sidetracking is not justifiable, or economic.
The field is located in the onshore area of Abu Dhabi about 110 km to the Southeast of Abu Dhabi Island1,2 and was discovered in 1965 in the Thamama Reservoirs. The field is an elongated faulted, doubly plunging anticline with the longer axis trending Northeast - Southwest. It is about 30 km long and 10 km wide. At top Thamama level, the flanks dip 3-5° on the western and eastern side and 1 - 2° on the northern and southern side.
This Thamama reservoir (Upper Kharaib Fm.) is the main oil bearing and producing reservoir in the field with light 40 API sweet crude. It can be subdivided roughly into an "upper" and a "lower" unit based on their depositional facies and reservoir properties, predominantly change of permeability (Fig. 1), with oil in place divided evenly between the two. The reservoir has been further subdivided into five units based upon the presence of dense stylolitic intervals that separate the reservoir rock (Fig 1). The dense units do not act as barriers to fluid flow or to pressure, but thicken from crest to flank of the structure. The thickness of the reservoir ranges between 191 ft in the crestal area and 165 ft down flank, with average porosity and arithmetically averaged permeability vary from a maximum of 34% and 363 mD in the crestal area to a minimum of 20% and 10 mD down flank.
Wettibility of the reservoir is thought to become progressively more oil-wet from flank to crest, with initial water saturation ranging from 5 s.u. to 10 s.u. at the crest, depending upon rock quality, with increasing saturation toward the flank through a significant transition zone.