A Comprehensive Study of Sanding Rate From a Gas Field: From Reservoir to Completion, Production, and Surface Facilities

SPE Journal ◽  
2011 ◽  
Vol 16 (02) ◽  
pp. 463-481 ◽  
Author(s):  
Gang Han ◽  
Keith Shepstone ◽  
Iwan Harmawan ◽  
Ufuk Er ◽  
Hasni Jusoh ◽  
...  
Keyword(s):  
Laboratory Tests ◽  
Sand Particle ◽  
Sand Production ◽  
Collection System ◽  
Gas Field ◽  
Fundamental Physics ◽  
Management Platform ◽  
Sand Control ◽  
Gas Fields ◽  
Comprehensive Study

Summary An offshore gas field has been producing sand for a few years. Sand production has been closely monitored through acoustic flowline devices and a sand-collection system installed on the platforms. Observation of sand production has triggered evaluation of whether to install surface desanders or to complete future wells with downhole sand control. This evaluation requires a prediction of sanding rate over the reservoir life. The possibility of providing downhole sand control on existing wells was also evaluated in separate studies. Predicting sanding rate, particularly for gas fields, has been historically challenging, mainly because of the sporadic nature of sand production, inadequate quantification of fundamental physics, and lack of representative laboratory tests and reliable field calibration. To tackle these challenges, four studies have been designed and executed: (1) the development of a reliable log-based rock-strength estimate, (2) the prediction of sanding rate over the reservoir life for a conservative well condition, (3) the evaluation of sand-particle transport from the reservoir to the surface facilities, and (4) the estimate of potential erosion of platform facilities. The sanding-rate prediction is based on extensive laboratory tests of four carefully selected whole cores with gas and water flow. It then has been validated by field-monitoring data from an acoustic flowline device on each producer and a sand-collection system on the platforms. The studies have provided a prediction of (1) future sand production, (2) how much of the produced sand will be seen at the surface (and, therefore, how much of it will fall into the rathole), (3) how fast various components of the surface facility will erode over the field life, and (4) what will be the optimal completion strategy for sand control should it become necessary. They have provided input to an integrated evaluation of completion design, reservoir management, platform configuration, and field economics.

Implications of accurate geomechanical modelling and systematic core testing for sanding evaluation and sand control decisions – a case study from Perth Basin

2020 ◽  
Vol 60 (1) ◽  
pp. 267
Author(s):  
Sadegh Asadi ◽  
Abbas Khaksar ◽  
Mark Fabian ◽  
Roger Xiang ◽  
David N. Dewhurst ◽  
...  
Keyword(s):  
Management Strategies ◽  
Mechanical Tests ◽  
Well Test ◽  
Sand Production ◽  
Gas Field ◽  
Stress Regime ◽  
Full Field ◽  
Field Development ◽  
Sand Control ◽  
Rock Mechanical Properties

Accurate knowledge of in-situ stresses and rock mechanical properties are required for a reliable sanding risk evaluation. This paper shows an example, from the Waitsia Gas Field in the northern Perth Basin, where a robust well centric geomechanical model is calibrated with field data and laboratory rock mechanical tests. The analysis revealed subtle variations from the regional stress regime for the target reservoir with significant implications for sanding tendency and sand management strategies. An initial evaluation using a non-calibrated stress model indicated low sanding risks under both initial and depleted pressure conditions. However, the revised sanding evaluation calibrated with well test observations indicated considerable sanding risk after 500 psi of pressure depletion. The sanding rate is expected to increase with further depletion, requiring well intervention for existing producers and active sand control for newly drilled wells that are cased and perforated. This analysis indicated negligible field life sanding risk for vertical and low-angle wells if completed open hole. The results are used for sand management in existing wells and completion decisions for future wells. A combination of passive surface handling and downhole sand control methods are considered on a well-by-well basis. Existing producers are currently monitored for sand production using acoustic detectors. For full field development, sand catchers will also be installed as required to ensure sand production is quantified and managed.

From Wellbore Breakout to Sand Production Prediction: An Integrated Sand Control Completion Design Methodology and Case Study

2021 ◽  
Author(s):  
Caleb DeValve ◽  
Gilbert Kao ◽  
Stephen Morgan ◽  
Shawn Wu
Keyword(s):  
Particle Size ◽  
Sand Particle ◽  
Well Performance ◽  
Sand Production ◽  
Natural Sand ◽  
Reservoir Development ◽  
Sand Control ◽  
Production Wells ◽  
Sandstone Reservoir

Abstract Controlling downhole sand production is a well-known and often-studied issue within the oil and gas industry. The methods employed for sand management, and their ultimate cost, is greatly impacted by the amount of sand produced by the well. This paper presents an innovative, physics-based approach to predict sand production for various reservoir and completion types, explored through a case study of recent production wells in a sandstone reservoir development. Sand control may be executed through a variety of methods, for example at the reservoir-completion interface using a sand control completion, at topside facilities through sand monitoring / de-sanding equipment, or by using well operational limits to avoid downhole sand failure. Although different strategies exist for effective sand management, some capability to estimate sand production is needed to design a holistic sand management strategy. This paper presents a physics-based approach to predicting sand production on a well-by-well basis to inform the overall sand management design. The workflow integrates (1) geomechanical estimate of wellbore breakout and volume of failed sand downhole, (2) log-based prediction of the sand particle size variation along the well path, (3) modeling of sand filtration based on experimental and analytical methods for specific completion options (e.g. Open Hole Gravel Pack [OHGP] or Stand-Alone Screen [SAS]), and (4) a natural sand pack permeability prediction for SAS completions and associated well performance analysis. This paper describes the methods used in this work in more detail as well as the application to five wells in a recent sandstone reservoir development. The workflow can be described as follows: First, log-based predictions for geomechanical properties and sand Particle Size Distributions (PSDs) were generated for specific wellpaths, and the volume of failed reservoir sand and PSD characteristics were predicted along the entire wellbore length. Next, this analysis was combined with a novel filtration model to determine sand retention and production, specific to various completion types. Additionally, for a SAS completion, the PSD and volume of retained sand in the annulus was computed as the wellbore experience borehole breakout, combined with an analytical model to calculate the natural sand pack permeability and well performance. This workflow was initially applied to study five development well producers, and the results influenced a mixed design of OHGP and SAS completions for individual wells. Sand production was measured during recent well startup to validate the workflow, with excellent agreement observed between measured field data and the physics-based predictions. This innovative, physics-based approach and the associated case study demonstrate a significant advancement in the area of sand production prediction from hydrocarbon production wells. The current workflow is able to deliver improved sand prediction capabilities over rules of thumb or analog field performance, which can be used to better inform overall sand management strategies and associated business value.

New Downhole Sand Entry Detection Technology Leads Directly to Successful Remedial Work and Additional Oil Production

2021 ◽  
Author(s):  
Gaurav Agrawal ◽  
Moustafa Eissa ◽  
Kamaljeet Singh ◽  
Shaktim Dutta ◽  
Apoorva Kumar ◽  
...  
Keyword(s):  
Reservoir Characterization ◽  
Sand Particle ◽  
Gas Oil ◽  
Sand Production ◽  
Impact Detection ◽  
Detection Tool ◽  
Detection Technology ◽  
Sand Control ◽  
Remedial Work ◽  
Interpretation Algorithm

Abstract The consequences of sand production are often disadvantageous to the short and long-term productivity of the well. Although some wells routinely experience controllable sand production, these are the exception rather than the rule. Sand production and its management over the life of the well is not an attractive situation but is often essential to extract the resource. Knowing the root cause behind sand inflow in a well and the possible results can inform an appropriate strategy to safely extract as much of the resource as possible. The sands in such reservoir units often have high permeability and are mechanically weak and prone to sand production. The producing wells are often completed with gravel-packed completions for efficient sand control. Most of the wells have multi-zone completions for better productivity but this further complicates reservoir characterization. This paper describes the first use of downhole sand impact detection technology in such fields. The sand detection technology integrates the fully digitized high-resolution acquisition with signal processing and interpretation algorithm to enhance the sand particle detections as small as 0.1 mm in diameter and up to 1,500 impacts per second. The tool is designed to immune the sensors from any background noise and gas/liquid jetting effect. A combination of production logging tools (PLT) and the sand impact detection tool, was used to understand four phase zonal contributions (gas, oil, water and sand) and pinpoint sand entry in these cases. Results exceeded expectations and the ability for the sand detection tool to accurately detect the point of sand entry enabled immediate intervention to eliminate sand production in these case studies. One of them also resulted in increased production of 7.4kb/d oil without any sand flow and with greatly reduced gas-oil ratio as compared to pre-intervention production. The work clearly demonstrates the practical and effective use of downhole sand impact detection with new sand detection technology to identify and isolate sand production in wells. The innovative tool design makes it feasible to detect even small sand particles in adverse wellbore conditions and varied production rates, thus adding a detection of the fourth phase in an otherwise three phase production log.

Value of Managing the Subsurface Risks and Uncertainties in the Project Execution; A Successful Case History in Merakes Green Gas Field Development

2021 ◽  
Author(s):  
Dian Kurniawan ◽  
Gabriela Carrasquero ◽  
Edo Richardo Daniel ◽  
Kurnia Wirya Praja ◽  
Elisa Spelta ◽  
...  
Keyword(s):  
Data Acquisition ◽  
Reservoir Characterization ◽  
Quantitative Description ◽  
Mitigation Strategies ◽  
Sand Production ◽  
Gas Field ◽  
Field Development ◽  
Extensive Evaluation ◽  
Sand Control ◽  
The Way

Abstract Implementing a proactive approach with comprehensive reservoir characterization, risks identification and mitigation are key elements that have to be deeply investigated before the project execution for achieving the optimum results in field development. A tremendous result on the seismic driven field development and synergy with a fast track development concept in Merakes green gas field has been achieved. In this paper, the conceptual and methodologies are described in the way of managing the subsurface risks and uncertainties during the planning and execution phase. A suitable example in Merakes field development which classified as "appraisal while developing", since the remaining risks still exist during development campaign, is presented. By having only two exploration wells with limited data, a robust upfront reservoir characterization and modeling were quite challenging to provide a reliable image of the subsurface condition. The enhancement on the way of constructing an integrated reservoir study prior to the field development is considered an essential requirement that has to be done before the project execution. A comprehensive approach that maximizes the integration of Geology, Geophysics and Reservoir Engineering disciplines and brings out the reservoir risk quantification has been considered as a basis and strategic driver for both subsurface quantitative description and de-risking of development wells locations. Focusing on the subsurface risk criticality, the compartmentalization, rock facies quality, gas-water contact depth and sand production were considered as the main critical aspects that could impact the final success. Preserving mitigation strategies and adapting development flexibility concept have been prepared to overcome such subsurface unexpected conditions. A description of the well placement strategy which widely open to be optimized during the drilling campaign was allowed and brought benefits in mitigating the compartmentalization risk. The readiness of an adequate and comprehensive data acquisition program including log data acquisition, coring and well testing in the development wells has been prepared. Moreover, a sidetrack contingency plan has been also considered for a key-well in case of worse than expected results. With know-how and experiences on the nearby field development, an extensive evaluation of water and sand production risks was derisked by selecting smart completion and sand control technologies. A holistic integration between subsurface, drilling, petroleum, facilities disciplines is considered of paramount importance in development projects. The awareness of the field's risks and uncertainties allows maximizing efforts in following up the drilling phase promptly adapting the data acquisition plan to the effective level of residual uncertainty and related development risk. Eventually the good match between the expected scenario and the actual well results allowed to cancel most of the costly data acquisition plans which contributed to a positive impact on the project cost and time-saving.

Hanging Screen Evaluation to Unlock Marginal Sandy Reservoir: Case Study of Peciko Gas Field, Indonesia

2021 ◽  
Author(s):  
Danny Hidayat ◽  
Rantoe Marindha ◽  
Triantoro Ade Nugroho ◽  
Reyhan Hidayat ◽  
Runi Kusumaning Rusdi
Keyword(s):  
Control Method ◽  
Low Cost ◽  
Sand Production ◽  
Liquid Loading ◽  
Control Cost ◽  
Gas Field ◽  
Production Phase ◽  
Sand Control ◽  
And Performance ◽  
Shallow Reservoirs

Abstract Peciko Field currently produces gas from multilayer sand-prone shallow reservoirs. Therefore, it needs sand control method to unlock these marginal reservoirs through low-cost intervention. Hanging screen has been reviewed as an alternative solution to minimize sand control cost while maintaining its robustness to maximize the recovery. This paper will present and evaluate the hanging screen installation and performance from subsurface to surface elements in Peciko field. Hanging screen implementation in Peciko will be evaluated in terms of ease of installation to its performance during production phase. Peciko wells are equipped with real-time monitoring system including Acoustic Sand Detector. Therefore, sand problems could be easily identified. Any indication of screen failure will be confirmed by checking the surface equipment like chokes and intrusive probes. Further intervention to retrieve the screen and perform visual check at surface can be executed to extend the verification. Filter size, placement method, clean-up, and sand sieve result will be gathered to identify the root cause and determine the best method to apply hanging screen as reliable sand control method. Nine installations in 2019 conclude that screen plugging, liquid loading, and combination of both are main issues in production phase. With three plugging cases from well Fx and E2x, it was found that excessive drawdown pressure triggers high gas velocity in perforation tunnel and causing excessive sand production that plugged the screen. These cases also prove that self-unloading by choke movement can lead to plugging if the drawdown pressure and gas rate are not monitored carefully. Commingle production in Ax becomes an issue in lifting performance when reservoir pressure declines and liquid was produced from several reservoirs. Limiting drawdown pressure gives smaller gas rate to lift the liquid and make the well died from liquid loading easily. Massive sand production in well E2x and E2y cause an increase in Top of Sediment (TOS) and lead to inaccessible screen even with multiple bailing attempts. A series of screen design, choke configuration, proper clean-up and continuous monitoring are critical steps to be performed prior and after screen installation to maintain production lifetime. With average stakes of 0.2 Bcf per well, hanging screen has proven to produce 67% of the well reserves in shallow reservoirs. This value creation led to the conclusion that hanging screen is an economically-feasible-sand control method to be implemented in Peciko.

Experimental Research on Erosion of P110 Tubing during Perforating

2014 ◽  
Vol 1073-1076 ◽  
pp. 2244-2247
Author(s):  
Hu Sun ◽  
Zhi Jun Ning ◽  
Zu Wen Wang ◽  
Zhen Li ◽  
Zhi Guo Wang
Keyword(s):  
Weight Loss ◽  
Erosion Rate ◽  
Large Scale ◽  
Guar Gum ◽  
Electrochemical Corrosion ◽  
Low Velocity ◽  
Gas Field ◽  
Weight Loss Method ◽  
Loss Method ◽  
Gas Fields

Erosion is a main failure of tubings and downhole tools in Changqing gas field. It is necessary to evaluate the erosion rate for the safety of tubing and strings. In this paper, the erosion of P110 steel, in the 0.2%wt guar gum fracturing fluid which contains sands, is investigated by weight loss method in the self-made jet experiment device. It is indicated that the erosion rate increases with the increment of slurry velocity exponentially. When the slurry velocity is in low velocity area, the electrochemical corrosion of dissolved oxygen dominates in erosion mechanism; when slurry velocity increases into middle velocity area, the weight loss is controlled by the synergism of corrosion-erosion; and when the slurry velocity increases into high velocity area, the weight loss rate is dominantly depended on erosion of particles. The results can provide guidelines for large-scale fracturing work of Changqing gas fields.

Pseudo Dry Gas Technology: Pathway to Decarbonisation of Energy Consumption for Remote Offshore Gas Fields

2021 ◽  
Author(s):  
Tran Nguyet Ngo ◽  
Lee Thomas ◽  
Kavitha Raghavendra ◽  
Terry Wood
Keyword(s):  
Energy Consumption ◽  
Energy Transition ◽  
High Energy ◽  
Innovative Technology ◽  
Flow Loop ◽  
Gas Field ◽  
Power Requirement ◽  
Order Of Magnitude ◽  
Gas Fields ◽  
Technology Pathway

Abstract Transporting large volumes of gas over long distances from further and deeper waters remains a significant challenge in making remote offshore gas field developments technologically and economically viable. The conventional development options include subsea compression, floating topside with topside compression and pipeline tie-back to shore, or floating liquefied natural gas vessels. However, these options are CAPEX and OPEX intensive and require high energy consumption. Demand for a lower emission solution is increasingly seen as the growing trend of global energy transition. Pseudo Dry Gas (PDG) technology is being developed by Intecsea, Worley Group and The Oil & Gas Technology Centre (Aberdeen) and tested in collaboration with Cranfield University. This is applied to develop stranded or remote gas reserves by removing fluids at the earliest point of accumulation at multiple locations, resulting in near dry gas performance. This technology aims to solve liquid management issues and subsequently allows for energy efficient transportation of the subsea gas enabling dramatic reductions in emissions. The PDG prototype tested using the Flow Loop facilities at Cranfield University has demonstrated the concept’s feasibility. Due to a greater amount of gas recovered with a much lower power requirement, the CO2 emissions per ton of gas produced via the PDG concept is by an order of magnitude lower than conventional methods. This study showed a reduction of 65% to 80% against standard and alternative near future development options. The paper considers innovative technology and a value proposition for the Pseudo Dry Gas concept based on a benchmarked study of a remote offshore gas field. The basin was located in 2000m of water depth, with a 200km long subsea tie-back. To date the longest tieback studied was 350km. It focused on energy consumption and carbon emission aspects. The conclusion is that decarbonisation of energy consumption is technically possible and can be deployed subsea to help meet this future challenge and push the envelope of subsea gas tie-backs.

Marginal Gas Field Development through Innovative Sand Control Completion Concept

2016 ◽  
Author(s):  
M. Zamberi ◽  
M. Mohd Sallehud-Din ◽  
S. Shaffee ◽  
N. Nik Kamaruddin ◽  
M. B. Jadid ◽  
...  
Keyword(s):  
Gas Field ◽  
Field Development ◽  
Sand Control
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