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Collaborating Authors
Drillstem/well testing
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...)
Determining Average Reservoir Pressures in Multilayered Completed Wells Using Selective Inflow Performance (SIP) Technique
Ilyas, Asad (1 MOL Pakistan Oil & Gas Co. B.V Islamabad-Pakistan) | Arshad, Safwan (1 MOL Pakistan Oil & Gas Co. B.V Islamabad-Pakistan) | Ahmed, Jawad (1 MOL Pakistan Oil & Gas Co. B.V Islamabad-Pakistan) | Khalid, Arsalan (2 Schlumberger, Islamabad-Pakistan) | Mughal, Muhammad Haroon (2 Schlumberger, Islamabad-Pakistan)
ABSTRACT This paper describes the challenges in determining average reservoir pressures in multi-layer completed wells during the span of their production period. The wells with single production tubing and get comingled flow from different reservoir layers exhibit complex down holeflow profiles. Therefore, it becomes difficult to acquire average pressures of each producing layer separately. Production log data can be utilized in these kinds of wells to calculate average individual layer pressures with the help of Selective Inflow Performance (SIP) technique for better production allocation and also to monitor pressure depletion effects with time. The SIP provides a mean of establishing the IPR for each rate-producing layer. The well is flowed at several different stabilized surface rates and for each rate, a production log is run across the entire producing interval(s) to record simultaneous profiles of downhole flow rates and flowing pressure. Measured in-situ rates can be converted to surface conditions using PVT data. Although SIP theory only applies to single phase flow, the interpreter can restrict the IPR's computations to a particular phase; only contribution of the selected phase will be taken into account. To each reservoir zone corresponds for each survey/interpretation a couple [rate, pressure], used in the SIP calculation. The different types of IPR equations can be used for SIP interpretation: Straight line, Fetkovitch or C&n, and LIT relations. In the case of a gas wells, the pseudo pressure m(p) can be used instead of the pressure "p" to estimate the gas potential. Although SIP is a useful technique to estimate average reservoir pressure in multi-layered system, but it has some limitations under certain circumstances. The Selective Inflow Performance (SIP) technique has been implemented on some of the producing wells in north of Pakistan. These wells have been completed in multiple producing reservoirs. Initially all these reservoirs were tested separately (with DST) to estimatetheir reservoir pressures and other parameters. However, due to adapted completion strategy, the producing layers were comingled with the option to monitor each layer's pressure depletion with the help of SIP technique in future. As per reservoir surveillance activity, Production logs are run on routine basis by utilizing SIP method and the same has been utilized for reservoir management and for simulation model updates.
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract Description Oil industries with higher potential reservoirs are having restrictions to maximize the oil production when the gas handling capacities are limited with considerations to environment. There can be other limitations such as water handling capacity and well-head sensitivity limitations. To overcome these limitations this paper provides a comprehensive method, which was developed with combination of mathematical tools like curve fitting techniques to build well model from production test results and linear/ nonlinear programming for optimizing the well models. Application This method summarized can be applied to optimize/ maximize oil production in matured fields, fields with limitation on gas handling and high GOR limitations. Principle used in this paper can be used in fields with water handling limitation also. This will help reducing impact on environment as well. Results and Conclusions Results for maximum oil which can be produced with the gas plant design conditions, limitations are provided in this paper and set of well choke opening for the optimum production are generated by program for different cases. Previous works used the approach to optimize mainly gas lift wells, this paper proposes for oil production optimization, moreover previous works created well performance curves on the basis of oil production or estimations, but this work is based on choke opening and well test results of encoded wells. Technical Contributions A novel method of combining well test data to interpolate oil, gas, water production equation (Well performance curves) in terms of well choke opening (which is decision variable) is used. This paper provides optimum oil produced from field, Maximum oil which can be produced from field with different Gas limitations, and field maximum oil production capacity. All the above results are generated without using any specialized software.
- North America > United States > Louisiana (0.55)
- North America > United States > Alaska > North Slope Borough (0.46)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- North America > United States > Alaska > North Slope Basin > Kuparuk River Field (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Ain Dar Field > Lower Fadhili Formation (0.99)
- (6 more...)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (0.94)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (0.89)
- (2 more...)
Abstract Over the field life, surveillance in Tengiz oil field has provided historical and baseline data for simulation history matching, static and dynamic reservoir characterization and modeling, and the foundation for efficient well management. Hence, it continues to be an important part of everyday field operations. At the surveillance planning stage, the comprehensive opportunity list of well candidates is developed based on input provided by members of multiple teams: geologists and petrophysists, production and reservoir engineers, drilling and field operations specialists. SCADA system, permanent downhole gauges (PDHGs) and multiphase flow meters (MPFMs) are widely implemented for production data acquisition and analysis. However, the majority of surveillance activities still need well intervention into the high pressure, high H2S concentration wellbores, often during harsh weather conditions. Each job execution plan is therefore focused on the safest procedure to obtain the necessary data. Each planned survey in the surveillance plan is ranked according to the value of information to be obtained, in order to help schedule the timing of surveillance based on plant production needs. The ultimate goal is to safely execute planned surveillance to support production optimization and field development work. This paper will highlight TCO success in addressing the different reservoir and well production uncertainties through a properly designed surveillance plan with both short and long-term objectives.
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Tengiz Formation (0.99)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Korolev Formation (0.99)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Korolev Field (0.99)
Abstract Multi-stage fractured horizontal wells (MFHW) in unconventional resource plays often present formidable reservoir management challenges, particularly with regard to capital utilization and allocation. In this study, well performance histories of some 74 wells in the Montney siltstone play were investigated with a common and consistent analytical framework. Parameters determined from the analyses are key indicators of the combined result of reservoir quality and hydraulic fracture performance (subsurface and completions). The analytical approach utilized in this study was then used to provide robust physics-based forecasts that directly recognize and incorporate interpretation non-uniqueness. Through a forecasting regimen that explicitly provides expected ranges of results, insights and conclusions in field optimization, well spacing and completions design have been drawn. A real distribution of well productivity and predicted recovery enabled identification of "sweet spots". Openhole completions technique did not show poorer performance compared to limited entry style completions, though further evaluation and surveillance would seem warranted. Wells that were flowing under a "high-drawdown" showed a lower productivity, higher completion resistance (skin) to flow, and lowest predicted final recovery. Wells completed at 50 m fracture spacing and 30 tonnes of proppant per cluster performed similarly to 100 m spacing and 60 tonnes per cluster, suggesting no apparent difference in capital efficiency between these two completion styles. Results indicate that the frac half lengths in the 50 m cluster spacing wells are shorter compared to wells with 100 m cluster spacing (based on the reduction in the amount of proppant pumped per cluster). Trends of estimated original gas-in-place inside the SRV and predicted 30-year recovery for wells drilled at close well spacings, (closer than 400 m between wellbores) indicate effects of inter-well interference. Performance of wells at 200 m well spacing seem to be affected the most by inter-well interference. A consistent workflow for analyzing well performance and predicting future performance of MFHW in unconventional gas wells is presented that provides a means to assess the impact of business and development decisions and determining practices worth replicating across the Montney play.
- North America > United States (1.00)
- North America > Canada > Alberta (0.67)
- North America > Canada > British Columbia (0.49)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.72)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.46)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract It is becoming increasingly common to commingle two or more separate gas reservoirs in a single wellbore, especially in stacked-sand environments such as those frequently found in the Asia-Pacific region. Providing certain conditions are met, the total gas initially in place (GIIP) of the commingled reservoirs can be estimated using conventional material balance techniques. However, allocation of total GIIP to individual reservoirs presents a significant challenge. This paper describes how production logging (PL) results can be used, in conjunction with suitable dynamic modeling techniques, to define GIIP on a zone-by-zone basis. The Selective Inflow Performance (SIP) technique for estimating pressures and deliverability of individual zones using suitable PL data is well established. Combining SIP results with other well information (including initial reservoir pressures and total well production) allows allocation of production to individual zones and calculation of their associated GIIP. This is done using a commingled well model (CWM) that matches both the initial well conditions and those obtained from the SIP results at the time of the PL. The paper sets out the minimum features of such a CWM. The ability to allocate production to an individual zone, and to estimate its associated GIIP, presents opportunities to make better reservoir management decisions than is possible when only total-well information is available. Such decisions, including the location and timing of infill or step-out drilling, or whether to target well intervention at particular zones, may have large financial repercussions.
Successful Application of Well Inflow Tracers for Water Breakthrough Surveillance in the Pyrenees Development, Offshore Western Australia
Napalowski, Ralf (BHP Billiton Petroleum) | Loro, Richard (BHP Billiton Petroleum) | Anderson, Calan (BHP Billiton Petroleum) | Andresen, Christian (RESMAN) | Dyrli, Anne Dalager (RESMAN) | Nyhavn, Fridtjof (RESMAN)
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Asia Pacific Oil and Gas Conference and Exhibition held in Perth, Australia, 22-24 October 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > WA-43-L > Block WA-43-L > Pyrenees Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > WA-43-L > Block WA-42-L > Pyrenees Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > WA-43-L > Block WA-12-R > Pyrenees Field (0.99)
- (17 more...)
Abstract There is a lack of comprehensive simulation tools that (a) accommodates the complexities of advanced completions together with near wellbore behaviour, and (b) has reliable wax precipitation models for production planning. In this work, these issues are tackled by combining three specific models. Firstly, a steady-state, three-phase, non-isothermal flow model in advanced horizontal completions was implemented to run fluid specific simulations, thereby calculating field specific flow conditions. This is useful in situations when fluid specific temperature calculations are important, such as wax crystallization. Secondly, a non-isothermal vertical flow model was developed by combining Hagedorn and Brown's multi-phase flow correlation with Ramey's multi-phase temperature model by solving them in sequence (iteratively). The advanced horizontal well model and vertical flow model were coupled iteratively at the bottom hole where the two models meet. Thirdly, two different analytical wax crystallization models were incorporated in the above coupled flow simulator to calculate the location of wax precipitation along the vertical section of the well. These three simulation models, individually and in combination, were tested and found to be in par with theory, expectations and published results. Additionally, significant difference was noted between Ramey's analytical temperature profile (which is a widely used approximation) and the complete Ramey's model integrated with the simulator developed in this work.
- Europe (0.93)
- North America > Canada (0.93)
- North America > United States > Texas (0.46)
- North America > United States > Louisiana (0.28)
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Russian Oil & Gas Exploration & Production Technical Conference and Exhibition held in Moscow, Russia, 16-18 October 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited.
Abstract Well productivity decline in mature gas fields, often attributed to liquid loading, may actually be due to salt deposition, which can produce identical symptoms. Salt plugging in gas wells has been well documented in Germany and the USA and is increasingly becoming an issue in the North Sea. There is an increasing awareness amongst North Sea operators of the issue of salt precipitation in gas wells, however, a recent literature search on the subject revealed a limited body of work suitable for use as an introduction to the subject. This paper reviews the mechanisms of salt precipitation, and looks at some modelling and monitoring methods and reviews the available remediation techniques Salt problems occur over a very limited range of producing conditions and are generally seen in mature, depleted gas fields, explaining perhaps the recent increasing interest in the issue amongst North Sea operators (UK and Netherlands). Salt solubility in water decreases with both reducing pressure and temperature, such as in a producing gas well, so that salt can precipitates as saturated produced water flows up the wellbore. The solubility effects are small but are exacerbated, or exceeded, by dehydration effects as produced water enters the wellbore. Salt may precipitate and adhere to the completion walls and produce a salt bridge. Salt can plug perforation tunnels and even form within the reservoir itself. It is not solely a downhole problem, salt precipitation can occur inside surface equipment such as compressors. For production operations, early detection or prediction of salt precipitation is vital, yet it has proved difficult as the issue depends on individual well conditions. The paper discusses how diagnostic modelling may help if certain data are available: produced water salinity, operating conditions along the wellbore and reliable WGR history. Finally, the paper describes current remediation techniques to restore gas well productivity.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (0.94)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (0.93)
- (6 more...)