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Collaborating Authors
Reservoir Description and Dynamics
Abstract Analytical models for 1-D displacement of oil by gas have been developed during the last 15 years. It was observed from semi-analytical and numerical experiments that several thermodynamic features of the process (MMP, key tie lines, etc) are not dependent on transport properties. After change of independent variables, the compositional (n-1)*(n-1) model for n-component flow is divided into a thermodynamics auxiliary (n-2)*(n-2) system and one transport equation. Explicit projection and lifting procedures are derived. The new technique developed permits splitting for both self-similar continuous injection problems and for non-self-similar slug injection problems. New different solutions for non-self-similar problems of gas injection in oil reservoirs are presented. With respect to 3-D flows, splitting takes place only for the case of constant total mobility (where the stream line concept is valid). For the general case of the total mobility variation, mixing between fluids that enter different streamlines occurs, and splitting does not happen any more. Introduction Enhanced Oil Recovery (EOR) methods include injection of different fluids into reservoirs to improve oil displacement. The EOR methods may be classified into the following kinds: chemical methods, solvents methods and thermal methods. Gas based methods of enhanced oil recovery include injection of different gases (methane, rich hydrocarbon gases, carbon dioxide, nitrogen and various combinations) in order to improve displacement by mass exchange between oleic and gas phases. This technique is also applied to improve the recovery of condensates after depletion of gas condensate reservoirs. An (n-1)ร(n-1) hyperbolic system of conservation laws describes one dimensional displacement of oil by gas in large scale, where n is the number of components. Continuous injection of gas results in a Riemann problem, while the displacement of oil by a gas slug with another gas drive is described by an initial and boundary value problem with piece-wise initial data. The elementary hyperbolic waves in the 2ร2 system for two-phase three-component displacement can be described both analytically and graphically. Analytical 1D models for different types of ternary phase diagrams and boundary conditions related to injection of different fluids were developed using the same technique. The semi-analytical solutions for n-component gas flooding obtained by numerical combination of shocks and rarefactions waves allow thermodynamic analysis, minimum miscibility pressure (MMP) calculations and recovery estimates. This technique was developed for any number of components. A hyperbolic system for gas flooding is similar to the one of polymer flooding. The observation that concentration waves in 2-phase environment can be obtained from one phase multi component flow was used for the development of a semi-analytical Riemann problem solver for two-phase n components polymer flooding. The exact solutions for this problem with adsorption governed by Langmuir isotherm were obtained using 1 phase solution. This technique cannot be extended for non-self-similar problems of oil displacement by polymer slugs. An approach analogous to one phase polymer flooding was applied to develop a reduced system for gas flooding and exact solutions for the displacement of n-component ideal mixtures were obtained using the projection to an auxiliary system. These solutions along with the definition of the reduced system were further used for injection of different gases into different oils. The technique developed is valid just for the case of continuous gas injection and cannot be applied for non-self-similar slug problems.
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Best Practices from Super-Giant 3D-OBC Seismic Survey, Offshore Oil Field Abu Dhabi
Hagiwara, Hiroshi (ADMA-OPCO) | Belaid, Kamal (ADMA-OPCO) | Lilley, Graham (BP) | Corless, Denis (ADMA-OPCO) | Al-Kaabi, Musabbah (ADNOC) | Ajlani, Ghiath (ADNOC) | Abed, Atef (ADNOC) | Suwaina, Omar (ADNOC) | Shimada, Nobusuke (ZADCO) | Najia, Walid (ZADCO) | Bu-Alrougha, Hamad (ZADCO)
Abstract This paper presents the best practices and the lessons learnt from a comprehensive offshore 3D ocean bottom cable (OBC) seismic survey, which was successfully carried out over a super-giant offshore production oil field in Abu Dhabi by an integrated multi-disciplinary team from three different companies. This work highlights a wide range of challenges and achievements throughout the steps, from the feasibility study, data acquisition, processing, interpretation and advanced reservoir characterization studies. Introduction The super-giant oil filed discussed here is located in the offshore area of Abu Dhabi, United Arab Emirates. The field was discovered and came on stream in 1960s, and is currently producing from the Lower Cretaceous limestone reservoirs in plateau from over 700 wells. The main reservoirs are zonally divided and operated by two different companies: ADMAOPCO and ZADCO, and their main shareholder ADNOC has the sole-risk right to produce gas from deeper reservoirs. In spite of the magnitude and the production history, there was no seismic-data-driven structure evaluation carried out in this field till this work. This is partly because the acquisition of the regional 2D seismic lines crossing over this field was extremely difficult due to overcrowded surface facilities in the matured oil field, but it is mainly because there was little doubt regarding the field structural maps wh ich were derived from a large number of wells. However, in mid 1990s, the existences of major faults were highlighted from a review of existing 2D seismic data in the flank of the field, which raised the potentiality of the presence of major faults in the crestal area of the field. Accordingly, the importance of the 3D seismic survey over this field was emphasized among the operators, and as a result, a comprehensive feasibility study was initiated to foresee the value and practicality of the 3D seismic survey. Feasibility Study The feasibility study was conducted over the course of a full year from 1998 to 1999. The objectives were to:Determine the likelihood of a high-resolution 3D OBC seismic survey to reach required resolution and detectability for structural curvature, faults and fracture zones, porosity, oil-water and gas-water contacts, horizontal well steering and 3D time-lapse (4D) for gas & water flood fronts as a stretch goal. Provide a multi-scenario optimization for possible 3D seismic survey (geometry designs, logistics, acquisition, processing, value-of-information probabilistic analysis, costs, etc.) In order to achieve these comprehensive objectives, a special multidisciplinary team was formed by the three participating companies and their shareholder experts to work on a variety of technical aspects in geophysics, geology, reservoir engineering, petrophysics and economics. The study consisted of the following segments:Existing 2D seismic reprocessing & acoustic impedance inversion (AAI) analysis. 1D/2D simple & complex modeling (ray tracing & viscoelastic modeling). 4D rock physics / petrophysics analyses for various fluid substitution models. HSE analysis and risk assessment. Side scan sonar survey & 2D OBC seismic data test acquisition & processing. 3D OBC seismic data acquisition design & simulation including obstruction analysis. Tender specification, pre-qualification and bid analysis Value-of-information probabilistic economic. 2D/4C OBC seismic data test acquisition & processing.
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Zakum Concession > Zakum Field > Thamama Group Formation (0.98)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Abu Dhabi Field (0.97)
Phase Behavior Assessment of Deposition Compound (Asphaltene) in Heavy Oil
Tabibi, Mohammad (Petroleum Engineering Development Company) | Nikookar, Mohammad (Petroleum Engineering Development Company) | Ganbarnezhad, Rouzbeh (Petroleum Engineering Development Company) | Pazuki, Gloam Reza (Sharif University of Technology) | Hosienbeigi, Hamid Reza (Tehran University)
Abstract In this paper, the soave-Redlich-Kwong (SRK) Eos is modified based onperturbation theory. The parameter of the new cubic equation of stateconsidered reduced temperature and a centric factor dependent. The average ofabsolute deviations of predicted vapor pressure, vapor volume and saturatedliquid density of 30 pure compounds are 0.814.2.G14 and 5.814%, respectively.Also comparison with the new equation of vaporization of pure compounds aregiven. The florry-Hugines (FH) model is similarly modified by an adjustableparameter. This parameter is defined based on molecular weight of asphaltene tomolecular weight of heavy oil ratio in form of polynomial function. The phasebehavior of asphaltene was extended by these modifications and theprecipitation of asphaltene is calculated by three n-alkanes solvents. Thecomparison between results is shown. The new model relatively accurate forpredicting phase behavior of asphaltene in heavy oil. Introduction Deposition of complex and heavy organic compounds, which exist in petroleumcrude particularly in heavy oil, can cause a number of serious problems.Asphaltenes could flocculated under many different conditions, two commonlyconsidered examples an the asphaltenes produced by titration with n-alkanes andthose that appear during depressurization of live crude oils. Trbovich and King(1) listed 11 different causes of asphaltenes deposition (CO 2, rich gas), ph shift, maxing of crude streams, incompatible organic chemicals, stimulation, shear, pressure drop, streaming potential, temperature drop andcharged, bare metal surface one of the first thermodynamic models was developedby Hirschberg at all. This model considers the oil to be a binary mixture oftwo liquids (asphalt and solvent). In their model, asphalt (resin and asphaltene) precipitates as singlehomogeneous compounds. In 1987, Leontaritis and Mansoori(2)proposed athermodynamic-colloid model, which is capable of predicting the onset ofasphaltene flocculation. This model postulates that asphaltenes exist in the oil as solid particlesin colloidal suspension, stabilized by resins absorbed on their surface. Morerecently, Kawanka et al (3). Reported a continuous dynamic model in which theonset as well as the amount of asphaltene deposits can be predicted with themolecular weight distributions of asphaltenes. They considered asphaltenes to be heterogeneous poly dispersed polymers. Lark, Park and Mansoori (4) combined the two theories, namely, continuousthermodynamic model and steric colloidal model and developed the so-calledfractal aggregation model theory of heterogeneous polymer solutions for theprediction of the onset and around of asphaltene precipitations. In this study, the SRK equation of state is modified. Based on simplifiedtheory of hard-core model. Also the flory-Huggine model modified by adjustableparameters based on ratio of molecular weight of asphaltene to molecular weightof heavy oil. With using these modifications phase behavior of asphaltene inheavy oil mixture has been studied.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
High-Resolution Sequence Stratigraphy of the Kharaib Formation (Lower Cretaceous, U.A.E.)
Strohmenger, Christian J. (ADCO) | Weber, L.J. Jim (ExxonMobil Exploration Company) | Ghani, Ahmed (ADCO) | Rebelle, Michel (ADCO) | Al-Mehsin, Khalil (ADNOC) | Al-Jeelani, Omar (ADCO) | Al-Mansoori, Abdulla (ADCO) | Suwaina, Omar (ADNOC)
Abstract A new sequence stratigraphic framework is proposed for the Lower Cretaceous Kharaib Formation (Barremian and Lowermost Aptian) of the United Arab Emirates. This framework is based on the integration of core and well-log data from Abu Dhabi oil fields with outcrop data from Wadi Rahabah, Ras Al-Khaimah (U.A.E.). The Kharaib Formation is part of the late transgressive sequence set of a second-order supersequence, built by two third-order composite sequences. Fourteen fourth-order parasequence sets build into two third-order composite sequences and show predominantly aggradational and progradational stacking patterns, typical of greenhouse cycles. On the basis of faunal content, texture, sedimentary structures, and lithologic composition, eleven reservoir lithofacies and eight non-reservoir "dense" lithofacies are identified from core. These same lithofacies are also identified in time-equivalent rock exposures studied in Wadi Rahabah. The analyzed lithofacies range from open platform, lower ramp to restricted platform subtidal to intertidal environments. Intensively bioturbated wackestone and packstone, and interbedded organic- and siliciclastic-rich limestone characterize the three so-called dense zones (Lower, Middle, and Upper Dense Zone). Locally, mud-cracks, blackened grains, and rootlets are observed. The two reservoir zones (Lower and Upper Kharaib Reservoir Unit) correspond to the late transgressive and, dominantly, highstand systems tracts characterized by parasequence sets that show shallowing-upward trends from open platform, burrowed skeletal wackestone to skeletal, peloidal packstone and algal, coated-grain grainstone/rudstone, and rudist, algal floatstone/rudstone. Well-developed Thalassinoides firmgrounds (Glossifungites surfaces) indicate temporary cessation in sedimentation and cap several parasequence sets and parasequences. Stylolitic intervals within the reservoir units predominantly correspond to major facies changes related to third-, fourth-, and fifth-order sequence boundaries, parasequence set boundaries, and parasequence boundaries. In outcrop, low-angle clinoforms that cannot be seen in core data are observed within the highstand systems tract of the upper third-order composite sequence (Upper Kharaib Reservoir Unit). Integration of subsurface and outcrop data leads to more insightful and realistic geological models of subsurface stratigraphy. Introduction Large hydrocarbon accumulations have been discovered and produced from platform carbonates of the Upper Thamama Kharaib Formation in Abu Dhabi. The Kharaib Formation (Barremian and Lowermost Aptian) contains two reservoir units (Lower and Upper Kharaib Reservoir Unit) separated and encased by three zones of very low porosity and permeability, subsequently referred to as dense zones (Lower, Middle, and Upper Dense Zone). Thickness of the Upper Kharaib Reservoir Unit is between 150 and 170 feet, and thickness of the Lower Kharaib Reservoir Unit is about 80 feet. Highly permeable beds (several Darcy) that mainly consist of coated-grain grainstone and rudist floatstone/rudstone facies are recognized in Field-A (Fig. 1). Generally, reservoir quality (porosity and permeability) decreases from crest to flank across the structure. This is due to compaction and cementation caused by the interaction with formation water. Diagenetic patterns of Field-B, Field-C, and Field-D (Fig. 1) are significantly different to those observed in Field-A. Whereas Field-A displays very good petrophysical properties, only locally affected by minor early- and late-diagenetic events, the reservoir quality of Field-B, Field-C and Field-D is impacted negatively by early-diagenetic porosity-destructive calcite cementation. This early-diagenetic calcite cement prevented significant compaction but occludes much of the primary interparticle porosity of the grainstone facies.
- Asia > Middle East > Saudi Arabia (1.00)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.56)
- Africa > Middle East > Libya > Murzuq District (0.44)
- Asia > Middle East > Saudi Arabia > Thamama Group > Kharaib Formation (0.99)
- Asia > Middle East > UAE > Abu Dhabi > Rub' al Khali Basin > Habshan Field > Thamama Group > Habshan Formation (0.98)
- Asia > Middle East > Saudi Arabia > Thamama Group Formation (0.98)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Abu Dhabi Field (0.91)
- Reservoir Description and Dynamics > Reservoir Characterization > Sedimentology (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
Abstract Almost every drilling operation is a potential source of damage to well productivity, lost circulation, differential sticking and other related conventional Drilling problems. This paper re-visits the key damage mechanisims and provides a broad overview on how they occur during various oilfield operations, and their effect on well productivity. Also, lost circulation or fluid invasion potential in high permeability zones, large open fractures, heterogeneous carbonates with massive interconnected vugular porosity, or pressure depleted zones would be a major issue of concern during conventional drilling condition. The worst-case scenario would be a combination of one of these high permeability features with significant pressure depletion. In order to overcome the above problems while drilling, the industry developed a method to drill with a bottom hole pressure below the pore pressure, called Underbalanced Drilling - UBD As the majority of hydrocarbons being exploited today are found in existing pressure depleted or complex and lower quality Reservoirs with lots of the conventional drilling problems, this is where Underbalanced Drilling Technology can add value and in some cases reduce development cost. Soon, Underbalanced Drilling will become the standard field development technique, both Onshore and offshore, where the Geology and Reservoir are suitable. The paper reviews several case histories and real results highlighting the advantages of Underbalanced Drilling Technology in reducing Formation Damage, Lost Circulations and improving well productivity. Introduction The Oil and Gas Industry drills thousands of wells worldwide each year. From the Reservoir and Production Engineers perceptions, a successful well is one that achieves its maximum production potential with no, or minimal, formation damage. Unfortunately, this objective is rarely achieved when conventional overbalanced drilling is used where mud solids and mud filtrate invade the reservoir formation and impair the permeability around the well bore. Formation damage can occur during almost any stage of petroleum exploration and production operations. This paper describes in detail the main formation damage mechanisms that occur during conventional drilling operation and how it can be controlled and prevented using Underbalanced drilling technology. The severity of solids and filtrate invasion depends on mud rheology, the duration of exposure to mud system, over-balanced mud pressure, rock permeability, and mineralogical composition of reservoir rocks. The solids and filtrate invasion causes the so called "skin effect" which may be attributed to different damage mechanisms that can have significant impact on the production and/or injection rates. Therefore understanding the different mechanisms of formation damage is becoming an important task for reservoir engineers in the oil and gas industry, because it is the first step to be taken to prevent and further alleviate this problem. What is Formation Damage? Formation Damage was once defined as: "the impairment of the invisible, by the inevitable and uncontrollable, resulting in an indeterminate reduction of the un-quantifiable". Luckily, the fact that Formation Damage is inevitable and Uncontroll-able has been replaced by a more positive attitude: Underbalanced Drilling Technology
- Europe > Norway > Norwegian Sea (0.35)
- North America > United States > Louisiana (0.34)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- Well Drilling > Pressure Management > Underbalanced drilling (1.00)
- Well Drilling > Formation Damage (1.00)
- Well Drilling > Drilling Operations (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Abstract Operation of a mature pool requires increasing cost control and infrastructure optimization and consolidation to maintain profitability. The decision to initiate this type of reservoir management plan, sometimes described as harvest, is driven in part by reservoir performance analysis and in part by commodity prices at the time the decision is made. The impact is not limited to operating cost; it can affect reservoir performance itself and the ultimate recovery of reserves. This paper presents the account of a 3.7 TCF sour gas pool in Alberta, Canada and the technical impact of harvest on field operations, reservoir performance and ultimate recovery. The combination of new production decline analysis, well workover with surprising results, and key field observations led to a complete change in reservoir interpretation. A new model emerged where near wellbore regions are deeply damaged and the gas-water contact (GWC) is much lower than expected. Introduction Management of mature pools is not a new challenge. Numerous papers have been written over the years, addressing various technical aspects and aimed at increasing pool longevity. In the Western Canadian Basin, the surge of exploration and development activity in the 1950's and 1960's has left a legacy of very mature pools with many of these 40 to 50 years old pools still producing today. Alberta Energy and Utilities Board (EUB) records show that of the 30,000 gas pools discovered in Alberta, 2000 or 7% were discovered before 1970. These pools represent in the aggregate 15 TCF of remaining recoverable reserves, as of January 1, 2002, or nearly 40% of the total. Each of these pools was at some point declared mature based on the science of the day and treated as a harvest candidate, i.e. a pool with very limited upside where the best strategy is to control cost and produce what is left without further investment. In some cases this approach becomes a self-fulfilling prophecy. This paper uses the example of the Kaybob South Beaverhill Lake A pool in Alberta, Canada to demonstrate how a large carbonate reservoir can be pulled back from harvest mode to sustained development. First, a history of the main operational activities will be summarized. A description of pool geology and reservoir fluids will be presented next. Operational changes brought about by the perception of the pool as mature will be reviewed and their impact on reservoir surveillance and operation itself will be detailed. Events leading to the change in perception of remaining potential of this pool will be related. The latest drilling activity resulting from this paradigm shift and subsequent production performance will conclude this paper. Pool History The Beaverhill Lake A Pool is a large sour retrograde gas condensate reservoir located in the Kaybob South Field, near the town of Fox Creek, 250 miles northwest of Calgary, Alberta, Canada (Figure 1). It was discovered in 1961 at a depth of 10,500 ft. Initial reservoir pressure was 4722 psia, 1107 psia above dew point pressure. The reservoir is underlain by a large aquifer that has provided pressure support to the Beaverhill Lake A pool and to other hydrocarbon pools in the area. The Beaverhill Lake A pool was divided into three operational units. Kaybob South Beaverhill Lake Units No. 1 and No. 2 (BHL #1 and BHL #2) are operated by one company while another operates Kaybob South Beaverhill Lake Unit No. 3 (BHL #3). Figure 2 illustrates the three production units. Production started in 1968 in BHL #1. Secondary recovery in the form of lean sweet gas cycling was applied immediately to increase recovery of natural gas liquids (NGL) and condensate. Secondary recovery ended with gas blowdown in BHL #1 in 1983. Production started in 1970 and 1972 in BHL #2 and BHL #3 respectively; both switched to gas blowdown in 1990. The decision to proceed with gas blowdown was based upon the maximizing energy recovery given the projections of the time. The action coincided with the onset of low North American natural gas prices, below $2/mcf and an operational switch from sustained development to harvest mode.
- North America > Canada > Alberta > Yellowhead County (0.34)
- North America > Canada > Alberta > Woodlands County (0.34)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.24)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (29 more...)
- Reservoir Description and Dynamics > Reserves Evaluation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- (3 more...)
Abstract A study focused on the sedimentology framework and on the Static Core Rock Type determination has been carried out on the Permo-Triassic upper Khuff reservoir formation in order to improve the full field reservoir models of two Abu Dhabi Offshore gas fields. The comparison of results indicates that the Khuff formation can be described by twelve lithofacies corresponding to five main depositional environments ranging from sabkha to oo-bioclastic shoal. The sequence stratigraphy evolution of these depositional environments leads to establish a fine scale reservoir layering, which evidences a large extent of the defined lithofacies between the two investigated fields. The limit between the Permian and Triassic series has also been defined. The results obtained from the sedimentary setting between these two fields provide important keys for further sedimentological and reservoir layering studies regarding other Abu Dhabi fields. Eighteen Static Core Rock Types have been defined by combining lithology, lithofacies, pore type association and petrophysical properties (K, PHI, MICP). If three major Core Rock Type groups can be easily differentiated (Limestone, Fabric-Selective and Non Fabric Selective Dolomite), some differences related to the diagenesis intensity, especially the dolomitisation process and the late anhydrite precipitation, exist between the two fields. Consequently, the lateral extent of the Core Rock Types can be very variable within a defined reservoir layer. Mapping the Rock type variations requires both, full analysis and integration of all sedimentological, diagenetic and petro-physical data in order to better constrain a 3D full field model. Introduction The Khuff Formation is a major reservoir in the Middle East Gulf region and contains some of the world's biggest gas reserves. The reservoir facies of this formation developed on a very large regional carbonate platform which had a very low topographic relief. The large geographic extent of this platform system is responsible for the development of very extensive facies tracts. In detailed reservoir-scale studies, major facies changes are often not considered; large areas need to be investigated for such a purpose. The Upper Khuff formation is described by four reservoir subdivision named in stratigraphically descending order: K1 to K4. These four reservoirs are separated by dense limestones. If the thickness of each of these reservoirs is quite constant at a field-scale, the reservoir quality and the well productivity can be very variable. The aim of these issues is to better understand the facies distributions, sequence stratigraphic architecture and the reservoir development within the Upper Khuff formation by comparing the geological architecture of two offshore Abu Dhabi fields. Available Data and Methodology The work flow developed to conduct the present Static Core Rock Typing study has been governed by the amount, the type and the quality of the available data. Field A: 10 active wells with a complete wireline log dataset, 4 cored wells (2482 ft), 1330 thin sections, 2480 Phi/K measurements and 75 MICP. Field B: 8 active wells with a complete wireline log dataset, 8 partially cored wells (3077 ft), 2750 thin sectionsand Phi/K measurements, 90 MICP. The absence of matrix density measurements (RHOm), of XRD analyses (clay contents, dolomite/calcite ratio) as well as the m and n factors does not allowed the classification of samples by petrophysical groups, i.e. sample group displaying an homogeneous petrophysical behaviour.
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (1.00)
- Asia > Middle East > Qatar (1.00)
- Asia > Middle East > Kuwait > Jahra Governorate (0.91)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Sedimentary Geology > Depositional Environment > Transitional Environment > Tidal Flat Environment (0.93)
- Asia > Middle East > Qatar > Khuff Formation (0.99)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Abu Dhabi Field (0.98)
- North America > United States > Kansas > Rock Field (0.89)
- Asia > Middle East > Iran > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Upper Khuff Formation (0.89)
- Reservoir Description and Dynamics > Reservoir Characterization > Sedimentology (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
Simulation Study of Miscible Gas Injection for Enhanced Oil Recovery in Low Permeable Carbonate Reservoirs in Abu Dhabi
van Vark, W. (Shell Abu Dhabi) | Masalmeh, S.K. (Shell Abu Dhabi) | van Dorp, J. (Shell Abu Dhabi) | Al Nasr, M. Abu (Abu Dhabi National Oil Company) | Al-Khanbashi, S. (Abu Dhabi National Oil Company)
Abstract In this paper we will present the outcome of a study conducted to evaluate the feasibility of large scale injection of sour and/or acid gas into a low permeable carbonate reservoir to enhance oil recovery. Other than for disposal, H2S containing mixtures have rarely been injected as a miscible agent in oil recovery projects. Moreover, the very few projects that have actually been executed are relatively small (generally less than 10 MMscf/d). In this study different recovery processes were evaluated such as water flooding, lean gas injection, sour gas (natural gas with a large H2S content) injection, acid gas injection, acid gas (mixture of H2S and CO2) after a slug of sour gas and CO2 injection. To evaluate these different (EOR) recovery processes, a detailed reservoir description is essential and for this purpose element-models were used. The critical importance of a thorough understanding of reservoir geology and rock properties for miscible gas injection schemes has been confirmed by [JLA1][JLA2] the experiences of water breakthrough and over-ride in a number of reservoirs in Abu Dhabi and the poor performance of some miscible gas injection projects in the industry. The simulation study shows that miscible acid gas injection is the preferred recovery mechanism for part of the reservoir under study. This is a result of several key factors, including the favorable miscibility with the native oil (lower miscibility pressure with reservoir crude), better solvent for asphaltene, a more favorable mobility ratio due to high acid gas viscosity and density and availability of large quantities of acid gas from the underlying formation. Acid gas is therefore an attractive, low cost, miscible, enhanced oil recovery agent, provided fully adequate corrosion mitigation procedures and HS&E management systems are implemented in the development. Introduction The class of reservoirs that are the subject of this investigation into the merits of alternative gas injection are large, high N/G, about 50 m thick carbonate reservoirs. Water injection has been the prime recovery process in these reservoirs that do not have a substantially natural water drive. In these large reservoirs properties vary and flank areas often show a severe reduction in permeability. Vertically averaged permeability is often more than 100 mD in the crest but deteriorates to less than 10 mD at the periphery. With such low permeability, waterflooding quickly looses its attractiveness, as it will require a very dense well spacing or result in a protracted field life. The use of gas as an injectant alleviates these drawbacks to a certain extent, but due to the lower viscosity the gas injection process is less efficient than water injection. Moreover, injection of lean (high methane content) gas carries significant cost, as there is a market for gas in the region. Large volumes of sour gas are encountered in the region and are often found directly below the oil reservoirs. Mainly because of the vast HSE complexities associated with producing large volumes of H2S, these sizeable volumes are so far untapped. Safe handling of H2S remains a challenge, in particular from a sustainable development perspective. However, in-depth studies have demonstrated that the safety aspect can be managed within a sound economical framework [1]. This paper reports about a simulation study that was undertaken with the objective of identifying the impact of alternative (gas) injectants on the recovery factor for the low permeable areas of these large carbonate oil reservoirs.
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
Abstract The most difficult practice in the oil industry is to displace oil in the low permeability zones in a heterogeneous reservoir. This situation becomes worse when the permeability contrast is high and is hydrocarbon properties dependant. In this study, experiments were conducted to investigate on how to temporarily plug the high permeable zones and flood the low permeable zones within the reservoir. Plugging the high permeability zone temporary is important because fluid segregation might complicate the outcome of production management. Different permeability contrasts of rock samples were used in the experiments. These experiments were conducted in the presence of one type of oil followed by water injection, while injection fluid properties, quality, injected slug size and velocity were controlled. Results show that the injection of mixed surfactants-fluid followed by water could stand plugging the high permeability zone and diverting water injection into the low permeability zones. Though, the mixture should be pumped with certain pore volume. Only some specific surfactants-fluid mixture (not used in the oil industry) resulted in stable fluid for the diversion process. When water was followed by the mixture, most of the oil in the low permeability zones were removed and flowed out of the rock. Certain slug sizes were needed in different permeability contrasts. As a result of the experiments, an easy way was observed to predict fluid rate and quality from laboratory experiments before the application in the field. Field application confirmed the lab experiments and higher production rate were managed. Introduction Producing oil from the low permeability zone in a heterogeneous reservoir that has high-permeability contrast is not easy. Different types of polymers and other fluids have been tried with no success. However, the use of foam in a heterogeneous porous media helps to reduce liquid mobility across the high permeability layers. This reduction in mobility causes the diversion of most of the injected liquid to the lower permeability layers. It is generally accepted that foam, in the presence of oil, does not help in mobility reduction. Laboratory experiments showed that foam propagation was usually retarded because of the presence of oil and in some cases there was no mobility reduction until the oil saturation became low enough. Minssieux proposed to use stabilizing agents capable of increasing the viscosity of the aqueous phase (such as a polyvinyl alcohol) to stabilize foam in the presence of oil. In the field application, as Maini reported, the injected foam inevitably contacted some residual oil. This contact between oil and foam had a major effect on foam properties. However, the mixing of the injected foam agent with surfactants already present in the oil led to enhancement of foam properties when the two surfactants behaved synergistically. He also found that the formation of oil in water emulsion could be a factor in overall mobility reduction behavior. Nikolov et al reported that during the process of three phase foam thinning, three distinct films occurred: foam films (water film between air and oil bubbles), emulsion films (water between oil droplets), and pseudoemulsion films (water film between air and oil droplets). Their micromodel experiments showed that after a certain thickness of a pseudoemulsion film formed between the oil lens and the air bubble surface ruptures caused the oil to spread on the surface. This spread oil disturbed the mechanical equilibrium between the foam lamellae and their borders causing the entire frame to break. According to Jensen and Friedmann, polar components in the oil may be adsorbed at the gas-water interface instead of at the surfactant surface and might destabilize the foam. Hence oil could spread at the gas - water interface, resulting in a reduction of the local surface tension. Oil saturation above 15%, they concluded, must be displaced before surfactant foam is propagated, unless oil intensive foam is used.
Abstract Horizontal wells are ideal in tight reservoirs where economic production cannot be achieved by conventional vertical wells. One of the advantages of a horizontal well over a vertical well is that it can be fractured at a number of positions along its horizontal section. Tight reservoirs generally produce in transient state for a considerable part of their producing life. Therefore accurate transient inflow models are required, not just for well testing purposes, but also for production forecasting. The objective of this study is to determine the number and characteristics of the producing fractures along the horizontal segment of the well. A new analytical model is developed to describe the transient pressure response of a horizontal well intersected by several fractures in anisotropic reservoirs. The fractures along the horizontal wells are assumed to be rectangular and vertical, and either transversal or longitudinal relative to the well direction. They are also of finite conductivity, infinite conductivity, or uniform flux type. It is further assumed that the fractures are fully penetrating (2D Model) or partially penetrating (3D Model), the well is either open or perforated only at fractures. A new set of type curves are developed that include five flow regimes: Bilinear, Linear, Radial, Biradial, and Pseudo-radial. New equations have been developed describing the unique characteristics of the five flow regimes. These equations allow us to calculate: the number of active fractures, equivalent fracture conductivity and total system conductivity, equivalent half-fracture length, reservoir directional permeabilities, equivalent skin, and the total skin of the system without using type-curve matching. A step-by-step procedure is provided for calculating reservoir parameters of a multiple hydraulically fractured horizontal well and practical applications are carried out by solving some simulated examples. Introduction Ozkan presented an extensive library of solutions in terms of the Laplace transform variable, he considered a wide variety of wellbore configurations, different bounded systems, and homogeneous or double-porosity reservoirs. Chen and Raghavan used Ozkan's solutions in studying a multiply fractured horizontal well in infinite systems, they accounted for the interference between fractures by the superposition of influence functions, their work only dealt with 2D fractures in isotropic system. Larsen and Herge tried to solve the 3D fractures problem but they replaced the pressure in the fracture by the average pressure in the Z-direction and neglected flow in the fracture parallel to the horizontal well. The purpose of this paper is to: build an analytical model for a horizontal well intercepted by multiple fractures fully or partially penetrating in anisotropic reservoirs and apply Tiab's direct synthesis technique to the case of multiple hydraulically fractured horizontal wells. The cases of uniform flux, infinite conductivity and finite conductivity models are considered. Model Description The horizontal well and the series of vertical fractures, longitudinal or transversal, are depicted in Figure 1. The horizontal well lies along the Y-axis, and the fractures are parallel to the plane of the X-axis. For the case of longitudinal fractures the horizontal well and the fractures lie along the Y-axis. The model assumes that distinct fractures are created in a horizontal well and each fracture is assumed to have distinct properties and may be of different spacing. We make the assumption that the flow from the reservoir to the wellbore sections between fractures is negligible as compared with the flow from the reservoir to the fracture plane. Two fracture models are built in sequence. First, an infinite reservoir with multiple 2D fractures. Second, an infinite reservoir with multiple 3D fractures along a horizontal well with infinite conductivity wellbore. In addition, the horizontal well may contain several perforated intervals. We apply the uniform flux, infinite conductivity and finite conductivity solutions on each individual fracture.
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics (1.00)