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Collaborating Authors
Drillstem/well testing
Evaluation of the Effect of Asphaltene Deposition in the Reservoir for the Development of the Magwa Marrat Reservoir
Al-Qattan, A.. (KOC) | Blunt, M. J. (Imperial College) | Gharbi, O.. (Imperial College) | Badamchizadeh, A.. (CMG) | Al-Kanderi, J. M. (KOC) | Al-Jadi, M.. (KOC) | Dashti, H. H. (KOC) | Chimmalgi, V.. (KOC) | Bond, D. J. (KOC) | Skoreyko, F.. (CMG)
Abstract The Magwa Marrat reservoir was discovered in the mid-1980s and has been produced to date under primary depletion. Reservoir pressure has declined and is approaching the asphaltene onset pressure (AOP). A water flood is being planned and a decision needs to be taken as to the appropriate reservoir operating pressure. In particular the merits of operating the reservoir at pressures above and below the AOP need to be assessed. Some of the issues related to this decision relate to the effects of asphaltene deposition in the reservoir. Two effects have been evaluated. Firstly the effect of in-situ deposition of asphaltene on wettability and the influence that this may have on water-flood recovery has been investigated using pore scale network modes. Models were constructed and calibrated to available high pressure mercury capillary pressure data and to relative permeability data from reservoir condition core floods. The changes to relative permeability characteristics that would result from the reservoir becoming substantially more oil-wet have been evaluated. Based on this there seems to be a very limited scope for poorer water flood performance at pressures below AOP. Secondly the scope for impaired well performance has been evaluated. This has been done using a field trial where a well was produced at pressures above and substantially below AOP and pressure transient data were used to estimate near wellbore damage "skin". Also compositional simulation has been used to estimate near wellbore deposition effects. This has involved developing an equation of state model and identifying, using computer assisted history matching, a range of parameters that could be consistent with core flood experiments of asphaltene deposition. Results of simulation using these parameters are compared with field observation and used to predict the range of possible future well productivity decline. Overall this work allows an evaluation of the preferred operating pressure, which can drop below the AOP, resulting in lower operating costs and higher final recovery without substantial impairment to either water-flood efficiency or well productivity.
- Asia > Middle East > Kuwait (0.69)
- North America > United States > Texas (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Mauddud Formation (0.99)
- (3 more...)
Abstract The time taken to safely optimise a reservoir produced by artificial lift can be measured in weeks or months. Typically the well by well process is as follows: Well testing Amalgamation of the well test data with down hole gauge and ESP controller data Analysis of the data to find the existing operation conditions Analysis of the ESP pump curve operating point and optimisation limitations Sensitivity studies in software to assess the optimum frequency and WHP Notification for the field operations to action the changes Further well tests to verify the new production data. Analysis of the data to ensure the ESP and well are running optimally and safely at the new set points New technology enables this process to be performed in real time across the entire reservoir or field, significantly shortening the time to increased production and enabling real time reservoir management. Each artificially lifted well in the reservoir was equipped with an intelligent data processing device programmed with a real time model of the well. The processors were linked to a central access point where the operation of field could be remotely viewed in real time. Each well’s processor was provided with a target bottom hole flowing pressure to enable the optimum production of the reservoir. The real time system automatically compared the desired target drawdown values with the capability of the pumping system installed in each well, and automatically suggested the optimum operating frequency and well head pressure to achieve the target. Where the lift system was not capable of producing to the target bottom hole pressure, a larger pump was automatically recommended. As production conditions change the system adapted its recommended operating points to compensate and maintain target production. This paper discusses three case studies where real time optimisation and diagnosis lead to improved production from the reservoir.
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
- Asia > Middle East > Kuwait (0.15)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Production and Well Operations > Artificial Lift Systems (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Increasing Oil Recovery with CO2 Miscible Injection: Thani Reservoir, Abu-Dhabi Giant Off-Shore Oil Field Case Study
Aljarwan, Abdulla (ADMA-OPCO) | Belhaj, Hadi (Petroleum Institute, Abu Dhabi, UAE) | Haroun, Mohamed (Petroleum Institute, Abu Dhabi, UAE) | Ghedan, Shawket G. (Computer Modeling Group, Ltd, Calgary, Canada)
Abstract This paper aims to study the miscibility features of CO2 miscible injection to enhanced oil recovery from Thani-III reservoir. A Comprehensive simulation model was used to determine multi contact miscibility and suitable equation of state with CO2 as a separate pseudo component using one of the industry’s standard simulation software. Experimental PVT data for bottom hole and separator samples including compositional analysis, differential liberation test, separator tests, constant composition expansion, viscosity measurements and swelling tests for pure CO2 were used to generate and validate the model. In addition to that, simulation studies were conducted to produce coreflooding and slimtube experimental models, which were compared with the conclusions drawn from experimental results. Results of this study have shown comparable results with the lab experimental data in regards to minimum miscibility pressure (MMP) calculation and recovery factor estimation, where the marginal errors between both data sets were no more than 7% at its worst. Results from this study are expected to assist the operator of this field to plan and implement a very attractive enhanced oil recovery program, giving that other factors are well accounted for such as asphaltene deposition, reservoir pressure maintenance, oil saturation, CO2 sequestering and choosing the most appropriate time to maximize the net positive value (NPV) and expected project gain.
- North America > United States > Texas (0.93)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.50)
- 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)
- (22 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- (4 more...)
Abstract The well drainage pressure and radius are key parameters of real-time well and reservoir performance optimization, well test design and new wells' location identification. Currently, the primary method of estimating the well drainage radius is buildup tests and their subsequent well test analysis. Such buildup tests are conducted using wireline-run quartz gauges for an extended well shut-in period resulting in deferred production and risky operations. A calculation method for predicting well/reservoir drainage pressure and radius is proposed based on single-downhole pressure gauge, flowing well parameters and PVT data. The proposed method uses a simple approach and applies established well testing equations on the flowing pressure and rates of a well to estimate its drainage parameters. This method of estimation is therefore not only desirable, but also necessary to eliminate shutting-in producing wells for extended periods; in addition to avoiding the cost and risk associated with the wireline operations. The results of this calculation method has been confirmed against measured downhole, shut-in pressure using wireline run gauges as well as dual gauge completed wells in addition to estimated well parameters from buildup tests. This paper covers the procedure of the real-time estimation of the well/reservoir drainage pressure and radius in addition to an error estimation method between the measured and calculated parameters. Furthermore, the paper shows the value, applicability and validity of this technique through multiple examples.
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations (1.00)
Abstract The success of recent applications in underbalanced drilling (UBD) and managed pressure drilling (MPD) has accelerated the development of technology in order to optimize drilling operations. The increased number of depleted reservoirs and the necessity for reducing formation damage has also increased the need to apply UBD/MPD to such candidate fields. Several methods used the latest mechanistic multiphase flow models in order to predict bottomhole circulation pressure when performing UBD/MPD operations. A new model is developed that utilizes the latest mechanistic multiphase flow models; the developed model calculates the bottomhole circulation pressure as a function of surface injection rates, choke pressure and time. The developed model can be used in designing and optimizing UBD/MPD operations in terms of determining the correct injection rate and/or choke pressure. In addition, the developed model is used to utilize the reservoir energy to attain correct bottomhole conditions. The developed model in addition to utilizing the latest mechanistic models also reduce the error in calculating the bottom hole pressure by incorporating an algorithm in which the injection rates are calculated in-situ rather than assuming constant injection rates. The model is validated against data from literature and against a commercial simulator. Results show that the developed algorithm has increased the accuracy in predicting bottomhole pressure by incorporating the changes in new gas and liquid injection rates.
- North America > United States > Texas (0.95)
- Europe (0.94)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
Abstract Asphaltic and sand production problems are common production challenges in the petroleum industry. Asphaltic problem results from the depositions of heavy material (asphaltene) in the vicinity of the well which may cause severe formation damage. Asphaltic materials are expected to deposit in all type of reservoirs. Sand production refers to the phenomenon of solid particles being produced together with the petroleum fluids. These two problems represent a major concern in oil and gas production systems either in the wellbore section or in the surface treatment facilities. Production data, well logging, laboratory testing, acoustic, intrusive sand monitoring devices, and analogy are different techniques used to predict sand production. This paper introduces a new technique to predict and quantify the skin factor resulting from asphaltene deposition and/or sand production using pressure transient analysis. Pressure behavior and flow regimes in the vicinity of horizontal wellbore are extremely influenced by this skin factor. Analytical models for predicting this problem and determining how many zones of the horizontal well that are affected by sand production or asphaltic deposition have been introduced in this study. These models have been derived based on the assumption that wellbore can be divided into multi-subsequent segments of producing and non-producing intervals. Producing intervals represent free flowing zones while non producing intervals represent zones where perforations are closed because of sand or asphaltic deposits. The effective length of the segments of a horizontal well where sand and/or asphaltene are significantly closing the perforations can be calculated either from the early radial or linear flow. Similarly, the effective length of the undamaged segments can be determined from these two flow regimes. The numbers of the damaged and undamaged zones can be calculated either from the intermediate radial (secondary radial) or linear flow if they are observed. If both flow regimes are not observed, the zones can be calculated using type curve matching technique. The paper will include the main type-curves, step-by-step procedure for interpreting the pressure test without using type curve matching technique when all necessary flow regimes are observed. A step-by-step procedure for analyzing pressure tests using the type-curve matching technique will also be presented. The procedure will be illustrated by several numerical examples.
- North America > United States (1.00)
- Asia (0.68)
- Europe > Norway (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
An Iterative Solution to Compute Critical Velocity and Rate Required to Unload Condensate-Rich Saudi Arabian Gas Fields and Maintain Field Potential and Optimal Production
Al-Jamaan, Hamza (Saudi Aramco) | Zillur, Rahim (Saudi Aramco) | Bandar, Al-Malki (Saudi Aramco) | Adnan, Al-Kanan (Saudi Aramco)
Abstract Saudi Arabian non associate gas reservoirs produce various amounts of condensate depending upon field and reservoir. In most cases, these wells are hydraulically fractured and at the initial stage after such stimulation treatment, each well needs to unload high quantity of the pumped fluid to ensure full potential. If the liquid starts accumulating in the wellbore during production, the well productivity will gradually decrease and eventually may stop producing. If the gas flow velocity in the production string is high enough, the gas will continue flowing and will carry the liquid droplets up the wellbore to the surface. The minimum velocity and critical gas rate (Qcrit) are therefore the determining factors while producing a well or several wells from a condensate-rich field so as to ensure the stable field production rate and maintain production plateau. An analytical model has been developed to iteratively compute the critical velocity (Vcrit) and Qcrit, for given flowing wellhead pressure (FWHP), tubing diameter, and many other reservoir and completion properties. If the FWHP is set and a certain production rate is expected of a well, the program automatically computes the pressure drop due to friction, dynamic hydrostatic head, and the bottomhole pressure. Simultaneously, both Vcrit and Qcrit to unload the fluids are calculated. If the Qcrit is above the expected production rate, a different wellbore completion is automatically selected and computation is continued until Qcrit is lower than the expected rate of the well. If this is not possible, the program will display appropriate message. Several wells from a condensate gas reservoir are analyzed from a field that has to maintain certain production potential for a given number of years. The analyses show that the wells that are producing without intervention are those that are confirmed by this model to be flowing above the Qcrit. For wells that were intermittently producing and ultimately could not sustain production were producing at rates below the critical values. Using this iterative model, those rates are automatically adjusted or new completion string is suggested to bring them back into production.
- Asia > Middle East (0.94)
- North America > Canada > Alberta > Stettler County No. 6 (0.24)
- North America > Canada > Alberta > Starland County (0.24)
- (2 more...)
Abstract The reliability of the estimated parameters in well test analysis depends on the accuracy of measured data. Early time data are usually controlled by the wellbore storage effect. However, this effect may last for the pseudo-radial flow or the boundary dominated flow. Eliminating this effect is an option for restoring the real data. Using the data with this effect is another option that can be used successfully for reservoir characterization. This paper introduces a new technique for interpreting the pressure behavior of horizontal wells and fractured formations with wellbore storage. A new analytical model describes the early time data has been derived for both horizontal wells and horizontal wells intersecting multiple hydraulic fractures. Several models for the relationships of the peak points with the pressure, pressure derivative and time have been proposed in this study for different wellbore storage coefficients. A complete set of type curves has been included for different wellbore lengths, skin factors and wellbore storage coefficients. The study has shown that early radial flow for short to moderate horizontal wells is the most affected flow regime by the wellbore storage. For long horizontal wells, the early linear flow is the most affected flow regime by the wellbore storage effect. The most important finding in this study is the ability to run a short test and use the early time data only for characterizing the formation. This means there is no need to run a long time test to reach the pseudo-steady state. Therefore, from the wellbore storage dominated flow, the early radial and pseudo-radial flow can be established for horizontal wells and hydraulic fractured formations. A step-by-step procedure for analyzing pressure tests using the analytical models (TDS) and the type curves is also included in this paper for several numerical examples.
- Research Report > New Finding (0.54)
- Overview > Innovation (0.34)
Results from a Pilot Water Flood of the Magwa Marrat Reservoir and Simulation Study of a Sector Model contribute to understanding of Injectivity and Reservoir Characterization
Al-Kandari, I.. (Beicip-Franlab) | Al-Jadi, M.. (Beicip-Franlab) | Lefebvre, C.. (Beicip-Franlab) | Vigier, L.. (Beicip-Franlab) | De Medeiros, M.. (Beicip-Franlab) | Dashti, H. H. (*Kuwait Oil Company) | Knight, R.. (*Kuwait Oil Company) | Al-Qattan, A.. (*Kuwait Oil Company) | Chimmalgi, V. S. (*Kuwait Oil Company) | Datta, K.. (*Kuwait Oil Company) | Hafez, K. M. (*Kuwait Oil Company) | Turkey, L.. (*Kuwait Oil Company) | Bond, D. J. (*Kuwait Oil Company)
Abstract A pilot water flood was carried out in the Marrat reservoir in the Magwa Field. The main aim of this pilot was to allow an assessment of the ability to sustain injection, better understand reservoir characteristics. A sector model was built to help with this task. An evaluation of the injectivity in Magwa Marrat reservoir was performed with particular attention to studying how injectivity varied as injected water quality was changed. This was done using modified Hall Plots, injection logs, flow logs and time lapse temperature logs. Data acquisition during the course of the pilot was used to better understand reservoir heterogeneity. This included the acquisition of pressure transient and interference data, multiple production and injection logs, temperature logging, monitoring production water chemistry, the use of tracers and a re-evaluation of the log and core data to better understand to role of fractures. A geological model using detailed reservoir characterization and a 3D discrete fracture network model was constructed. Fracture corridors were derived from fractured lineaments interpreted from different seismic attribute maps: A sector model of the pilot flood area was then derived and used to integrate the results of the surveillance data. The main output is to develop an understanding of the natural fracture system occurring in the different units of the Marrat reservoir and to characterize their organization and distribution. The lessons learned from this sector modeling work will then be integrated in the Marrat full field study. The work described here shows how pilot water flood results can be used to reduce risk related to both injectivity and to reservoir heterogeneity in the secondary development of a major reservoir.
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Mauddud Formation (0.99)
- (4 more...)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Underbalance Drilling of an Above Sea Level, Sub-Hydrostatic Reservoir; Recompenses – A Case History
Malik, Saeed Aslam (1 Oil & Gas Development Company Limited, Pakistan) | Channa, Munsif Hussain (1 Oil & Gas Development Company Limited, Pakistan) | Majeed, Arshad (1 Oil & Gas Development Company Limited, Pakistan) | Latif, Muhammad Khalid (1 Oil & Gas Development Company Limited, Pakistan) | Asrar, Muhammad (2 Weatherford, Pakistan)
Abstract During this period of energy crisis in Pakistan every effort is being made to produce every molecule of subsurface hydrocarbons. Particularly, the gas reservoirs which were not brought on production, due to low well deliverability or lack of required technology in the past are being explored and exploited. These include Tight, Low BTU, Sour and Acidic gas reservoirs. Such reservoirs pose specific problems related to drilling, production and development aspects. This paper depicts drilling and testing of a reservoir which is above sea level and its initial reservoir pressure is approximately 1000 psi below the normal hydrostatic pressure. It is one of the lowest pressure reservoirs of the world which has been drilled with successful flow of gas. Underbalance drilling technology was chosen to drill this challenging reservoir. Primary objective of under balance Drilling (UBD) was to establish reservoir potential by acquiring virgin reservoir characteristics. Historically, three wells have been drilled to test this reservoir. First two wells were drilled using conventional drilling methodology, both the wells experienced heavy mud loses during drilling and it was difficult to evaluate the production potential of this low pressure reservoir. Afterwards, pay zone of SML in third well × #02 was drilled and tested using Underbalance Drilling technique. This paper further describes the problems faced by the operator to drill first two wells in terms of mud losses and evaluation of production potential of low pressure reservoir of SML. In conclusion, it was a successful application which happened due to exceptional team work from all project parties. This application has opened new horizons of exploration and production of such reservoirs particularly in Baluchistan and generally in Pakistan.
- Asia > Pakistan > Sindh > Central Gas Basin > Sui Main Limestone Formation (0.99)
- Asia > Pakistan > Central Gas Basin > Sui Main Limestone Formation (0.98)
- Well Drilling > Pressure Management > Underbalanced drilling (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)