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Results
Breakthrough Stimulation Method: Dilation Cyclic Extended Breakdown to Enhance Well Injection Performance and Stimulation Cost Efficiency in South Sumatra -Indonesia
Proboseno, Nayung Galih (PT Pertamina Hulu Rokan Zona 4) | Demak, Ridwan Kiay (PT Pertamina EP Cepu) | Riviana, Rina (PT Pertamina Hulu Rokan Zona 4) | Yanuardi, Ayi (PT Pertamina Hulu Rokan Zona 4) | Parsaulian, Sakti (PT Pertamina Hulu Rokan Zona 4) | Surya, Dayanara (PT Pertamina Hulu Rokan Zona 4) | Setiawan, Rudhy (PT Pertamina Hulu Rokan Zona 4)
Abstract Water injection is an essential part of brown oilfield development plan both of pressure maintenance or water production management. The high cost and often tight economic margins associated with injection wells capacity require that the chosen stimulation technique not only provides an effective result to maximize injection well capacity but also carries an acceptable risk in term of the project cost and safety. Many well known techniques, such as fracturing and matrix acidizing have been developed over the years to achieve this result and are common in most water injection well operations. The objective of this paper is to show a new approach of stimulation technique can be maximized both of injection capacity and cut operational cost Dilation Cyclic Breakdown is a breakthrough stimulation technique through hydraulic treatment by injected high volume of formation water into the reservoir below tensile stress and above shear stress. The primary design that have led to these technique include the following steps : Certain criteria were used for pilot well such as hall plot and single well of nodal analysis. Operation can be performed by rigless operation and no chemical additive needed, equipment selection is approached by 3D fracture simulator both surface pressure and injection rate correlated to mechanical earth model syntethic. Pumping schedule and the number of cycle is optimized by pressure calibration analysis during Breakdown test, Step Rate Test and decline pressure analysis. It was critical that Step Rate Test and decline pressure analysis procedure be performed to determine fracture gradient as upper bound pressure and shear gradient as lower bound pressure. Various procedures were used in handling data recorded. Injection and pressure data from each well were plotted to observe the trend in the rate - pressure relationship. Nine injection wells were stimulated during 2020 - 2021. It has been an attractive result both of cut operational cost and increase injection capabilities. The operational cost per well can be reduced to $ 46,000 or 72% cheaper than matrix acidizing stimulation and the total incremental injection rate reach to 14,907 Bwipd or 1,656.3 Bwipd per well. A half of those injection wells were previously stimulated by matrix acidzing method but has not yet improved significantly. In addition, this method is also applied for two oil producer wells in sandstone reservoir as a pilot test. The increasing of Productivity Index greater 6.5 - 8x than initial as a result and has still been observed. Furthermore, this paper should be beneficial to all engineers currently working in brown and marginal Oil Field with tight economic margins to increase the production.
- North America > United States > Texas (1.00)
- Asia > Indonesia (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.93)
- Asia > Indonesia > Java > Northwest Java Basin > Talang Akar Formation (0.99)
- Africa > Cameroon > Gulf of Guinea > Rio Del Ray Basin > Etinde Block > ID Field > Upper Isongo Formation (0.99)
Infill Horizontal Well Placement Optimization and Execution Through Time-Lapse Cased-Hole and Open-Hole De-Risking Efforts Coupled with High Definition Geosteering Frontier Technology
Goh Jin Wang, Arthur (PETRONAS CARIGALI Sdn. Bhd) | Wahid Ali, Nurul Athirah (PETRONAS CARIGALI Sdn. Bhd) | Chuah Mei Mei, Stefanie (PETRONAS CARIGALI Sdn. Bhd) | Bt M Zaid, Siti Nurfarhana (PETRONAS CARIGALI Sdn. Bhd) | AL Naupa, Nagarajan (PETRONAS CARIGALI Sdn. Bhd) | Ain Sapian, Nik Fazril (PETRONAS CARIGALI Sdn. Bhd) | Bt Rafiuddin, Nur Liyana (PETRONAS CARIGALI Sdn. Bhd)
Abstract Managing complex brownfield production and sustainability expectations has become a norm in the oil and gas industry โ where opportunities to materialize resources can still be present. This paper covers the constructive practices in Field B, a 50-year-old brownfield offshore Malaysia in understanding uneven fluid movements dynamics via execution of time-lapse data acquisitions to justify planning for infill drilling. This has led to successful four (4) horizontal geosteering well placement in the major oil reservoir units. Time-lapse contact monitoring was made possible through integration of recent open-hole, production, dynamic simulations & cased-hole saturation logs in Reservoir A. Between the year 2014 to 2021, saturation logging campaigns were executed, and phenomena of uneven fluid contacts was observed between the un-faulted western to eastern areas of the field. Eastern area wells have observed shallower gas-oil contact (GOC) and oil-water contact (OWC) by 80 to 100ft-TVD, resultant from gas and water injections, disproportionate production withdrawal, potential gas leaks behind casing and stronger aquifer strength. The combination scenarios of geological structure and fluid contact uncertainties provided a range to drive geosteering pre-job modelling planning to sensitize multiple cases to optimize the well trajectories. The integrated ranges of current contact derived from saturation logs, recent open-hole logs and reservoir simulation constructed the basis of low-base-high remaining oil opportunity cases for planning and economic evaluations. Coupled with advancement of frontier technology Geosteering-HD, four (4) wells successfully penetrated 35 to 80ft-TVD of oil column in horizontal section and maintained along 1500-2000ft-AHD. Tilted oil-water OWC was observed in three (3) of the wells located at eastern area, where the OWC trends shallower from the heel to toe of the horizontal portion confirming the results from time-lapse contact information and contacts prediction from reservoir model. The other well drilled at western area, observed a mostly flat OWC throughout the horizontal section with slight tilting towards the toe, reflecting weaker aquifer strength at the western flank as observed in recent cased hole and open hole logging. The fluid contacts and structure penetrated in all four (4) wells are within the predicted low-base-high cases from pre-job modelling, leading to an optimum placement of horizonal well in the oil column. These optimizations have led to a successful infill campaign, delivering higher production rates of 5,600BOPD against planned 4,600BOPD for brownfield reserves acceleration. All data acquisition needs to be exhaustively studied and managed as each holds an important piece of evidence on what the field tries to express. In this field, the timely execution of time-lapse cased-hole logs integrated with open-hole results were vital and principal driver in de-risking fluid contact uncertainties within eastern and western area prior infill drilling for a successful horizontal well campaign.
- Asia > Malaysia (0.49)
- North America > United States > Texas (0.46)
- North America > United States > Texas > East Texas Salt Basin > Cotton Valley Group Formation (0.99)
- North America > United States > Louisiana > East Texas Salt Basin > Cotton Valley Group Formation (0.99)
- North America > United States > Arkansas > East Texas Salt Basin > Cotton Valley Group Formation (0.99)
Abstract Sand production prediction is essential from the early stages of field development planning for well completion design and later for production management. Unconsolidated and weakly consolidated sandstones are prone to fail at low flowing bottom hole pressures during hydrocarbon production. To predict the sand-free drawdown, a robust sand prediction model that integrates near-wellbore and in-situ stresses, rock mechanical properties, well trajectory, reservoir pressure, production and depletion trends is required. Sanding prediction models should be calibrated with field data such as production and well tests observation. In the absence of field data, numerical techniques can provide a reliable estimate on potential onset and severity of sanding at various reservoir pressures. In this study, analytical and finite-element numerical models are independently used to predict the onset of sanding and volume of produced sand from high rate has wells with weakly consolidated sandstone reservoirs in onshore, Western Australia. The analytical method uses a poro-elastic model and core-calibrated log-derived rock strength profiles with an empirical effective rock strength factor (ESF). In the study, the ESF was calibrated against documented field sanding observation from a well test extended flow period at the initial reservoir pressure under a low drawdown pressure. The numerical method uses a poro-elasto-plastic model defined from triaxial core tests. The rock failure criterion in the numerical method is based on a critical strain limit (CSL) corresponding to the failure of the inner wall of thick-walled cylinder core tests that can also satisfy the existing wells sanding observations. To verify the onset and severity of sanding predicted by the analytical model, numerical simulations for an identical sandstone interval are developed to investigate the corresponding CSL. This combined analytical and numerical modelling calibrated with field data provided high confidence in the sanding evaluation and their application for future well completion and sand management decisions. The analytical model was finally used for sanding assessment over field life pressure condition because of its processing simplicity, speed and flexibility in assessing various pressure and rock strength scenarios with sensitivity analysis over the whole production interval in compared with the numerical method which is more suitable for single-depth, single pressure condition and well and perforation trajectory modelling.
- North America (0.68)
- Oceania > Australia > Western Australia (0.48)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.98)
Understanding Source, Genesis and Spatio-Temporal Distribution of CO2 off the coast of Sarawak, Offshore Malaysia : An Integrated Approach
Masoudi, Rahim (PETRONAS) | Nayak, Satyabrata (PETRONAS) | Panting, Alexander Tarang Patrick (PETRONAS) | B M Diah, M Amri (PETRONAS) | Shah, Jamari M (PETRONAS) | Ismail, Ts. Hijreen Bt (PETRONAS) | Hoesni, M Jamaal (Beicip-Franlab Asia) | Razak, M Shafiq (Beicip-Franlab Asia) | Ahmad, Nur Asyikin (Beicip-Franlab Asia)
Abstract A regional CO2 concentration and risk maps have been generated for the Sarawak Basin using an integrated G&G and model-based approach. Detailed petroleum system modeling with number of scenarios encompassing critical parameter uncertainties is carried out. The extensive 3D petroleum system model carried out is critical in understanding generation, migration of hydrocarbon and CO2 as well as inter relation between the above two. This approach has significant advantage over traditional geostatistical method in extrapolation of observed data to predict CO2 concentration away from the control points. Apart from basin model detailed analysis of presence of CO2 in relation to temperature, tectonic features (faults lineaments) nature of the trap, pore pressure are carried out to identify and validate possible CO2 sources. This comprehensive study is the primary building block for generating a predictive model for CO2 distribution and possible adaptation in the prediction of other contaminants in the region.
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Sedimentary Geology > Depositional Environment (0.96)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.32)
- Asia > Malaysia > South China Sea > Malay Basin (0.99)
- Asia > China > South China Sea > Yinggehai Basin (0.99)
- Asia > China > South China Sea > Vung May Basin (0.99)
- Information Technology > Modeling & Simulation (0.55)
- Information Technology > Data Science (0.35)
A New-Type Eccentric Christmas Tree for Hollow Rod Electric Heating in Offshore ESP Wells
Fang, Tao (CNOOC Ltd) | Shang, Baobing (CNOOC Ltd) | Han, Xiaodong (CNOOC Ltd) | Zhao, Shunchao (CNOOC Ltd) | Zhou, Yugang (CNOOC Ltd) | Qi, Yadong (CNOOC Ltd) | Hao, Tongchun (China University of Petroleum Beijing)
Abstract The hollow rod electric heating (HREH) technology can greatly increase the temperature of the fluid in wellbore and improve its fluidity, which is widely used in rod pump wells. Bohai offshore oilfields also have urgent application requirements for HREH technology due to the wide distribution of heavy oil and high waxy crude oil. However, more than 90% of the oil wells there are produced by electric submersible pumps (ESPs). None of these christmas trees in use are suitable for ESP wells using HREH technology. Based on the conventional christmas tree with only one main channel, a new type of eccentric christmas tree, with separated main channel and cable channel, is designed. As with the conventional ones, the main channel works as the flow passage of wellbore fluids. And the cable channel is used to run and pull out the heating cable. The eccentric design of the main channel provides the space for the cable channel. The separate cable channel avoids the cable crossing the main channel, so that the master valve of the christmas tree can be opened and closed normally, which contributes to ensuring safe production. In the meanwhile, the christmas tree can also seal the heating cable owing to some special design. This new device has been successfully tested on 6 ESP wells in Bohai Bay. After the installation of the christmas tree, the cable was smoothly run down to the predetermined depth. The construction operation was simple and convenient. There was no oil or gas leakage at wellhead after it was put into use. The wellhead temperature of all these wells reached above 50ยฐC and no wax deposited in tubing any more, verifying its safety and reliability. This new type of safe and reliable christmas tree lays a solid foundation for the popularization and application of HREH technology, especially in those waxy oil wells and heavy oil wells with ESPs.
- Asia > China (0.48)
- North America > Canada > Alberta (0.30)
- Asia > Middle East (0.29)
- North America > United States > Texas (0.28)
Comparison of the Time-Lapse 4D Seismic Characteristics in MMV Between Carbonate and Clastic Reservoirs as CO2 Storage in Malay and Sarawak Basins, Malaysia
Tiwari, Pankaj Kumar (PETRONAS) | Das, Debasis Priyadarshan (PETRONAS) | Widyanita, Ana (PETRONAS) | Leite, Renato Jordan (PETRONAS) | Chidambaram, Prasanna (PETRONAS) | Patil, Parimal Arjun (PETRONAS) | Masoudi, Rahim (PETRONAS) | Tewari, Raj Deo (PETRONAS)
Abstract There are many gas fields associated with large amount of CO2 concentrations (>50 mol%) in offshore Malaysia. Development of the contaminated gas fields is only possible if a geologically safe storage site is identified for the storage of produced CO2. The critical component of CCS project field development plan is monitoring of the storage site for the long-term containment and conformance security. 4D time-lapse seismic is key in monitoring, measurement, and verification (MMV) plan. The time-lapse 4D seismic has been traditionally used to identify the potential threats associated with reservoirs with enhanced oil recovery plan. The application of 4D seismic would benefits CCS project for monitoring CO2 plume migration along existing or induced fractures. The study was conducted on identified CO2 storage sites in both depleted carbonate gas reservoir and clastic saline aquifer. It highlights two methods applied in the 4D AVO analysis, that quantifies the changes in CO2 saturation within reservoir during injection. The Aki and Richardsโ approximation were analyzed for the effect of changes in gas saturations on the seismic amplitudes and the Smith and Gidlow's approximation for the reflection coefficient relationship between the AVO gradient/intercept attributes and reservoir fluid/properties. The application of 4D seismic would benefits CCS project for monitoring CO2 plume migration along existing or induced fractures. The study was conducted on identified CO2 storage sites in both depleted carbonate gas reservoir and clastic saline aquifer. It highlights two methods applied in the 4D AVO analysis, that quantifies the changes in CO2 saturation within reservoir during injection. The Aki and Richardsโ approximation were analyzed for the effect of changes in gas saturations on the seismic amplitudes and the Smith and Gidlow's approximation for the reflection coefficient relationship between the AVO gradient/intercept attributes and reservoir fluid/properties. This study focuses on the different characteristics on 4D seismic attributes for carbonate and clastic reservoirs and discusses to effectively utilize for MMV.
- Asia > Malaysia > Sarawak > South China Sea (0.41)
- Asia > China > South China Sea (0.41)
- North America > United States > Texas (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 21/10 > Forties Field > Forties Formation (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Judd Basin > Block 204/25 > Greater Schiehallion Field > Schiehallion Field (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Judd Basin > Block 204/20 > Greater Schiehallion Field > Schiehallion Field (0.99)
- (10 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Four-dimensional and four-component seismic (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > CO2 capture and management (1.00)
Application of High-Definition Reservoir Scale Mapping-While-Drilling with Comprehensive Formation Evaluation in the Challenging Low Resistivity Contrast Environment
Wahid Ali, Nurul Athirah (Petronas Carigali Sdn. Bhd.) | Alang, Khairul Anuar (Schlumberger) | Wang, Haifeng (Schlumberger) | Goh Jin Wang, Arthur (Petronas Carigali Sdn. Bhd.) | Chuah Mei Mei, Stefanie (Petronas Carigali Sdn. Bhd.) | Sapian, Nik Fazril Ain (Petronas Carigali Sdn. Bhd.) | Bt M Zaid, Siti Nurfarhana (Petronas Carigali Sdn. Bhd.) | Rafiuddin, Nur Liyana (Petronas Carigali Sdn. Bhd.) | AL Naupa, Nagarajan (Petronas Carigali Sdn. Bhd.) | A Aziz, Khairul Ikram (Petronas Carigali Sdn. Bhd.)
Abstract The horizontal wells within the context of this case study are located offshore Malaysia, where the reservoirs vary in grain size and quality. The infill wells include 3 oil producer wells targeting S reservoir and 1 horizontal sidetrack well targeting R1-R3 subunit reservoirs. The horizontal wellsโ objective is to optimize minimum lateral length of 1,000-2,000ft MD at 1/3 vertical standoff from GOC within the target oil column. Based on recent data from offset wells, the fluid contacts (GOC and OWC) remained uncertain, hence well placement within the target oil column becomes the main challenge. The wells are expected to have low resistivity contrast between oil and water composition. In this kind of reservoir environment, the standard reservoir mapping tool may not be sufficient for differentiating reservoir fluid properties of oil and water bearing formation. For such challenging condition, an integrated real-time well placement technology, high tier triple-combo logs, Neutron Near- Far count and Formation Sigma measurements were deployed to fully achieve drilling objectives. 3 horizontal wells with 1 horizontal sidetrack well were successfully executed within the target zone, achieving objectives beyond expectation. A new generation of LWD tool including high-definition reservoir mapping-while-drilling technology with advanced inversion was deployed to fulfill geosteering requirements. The workflow presented in this project is a synergized scope of multi-domain, from both drilling and subsurface. This case study demonstrated the value of high-definition reservoir scale mapping technology. It provides an innovative and deterministic method to identify low resistivity low contrast boundaries of oil from transitional water zone which was difficult to be achieved by conventional reservoir mapping tool. At the landing section, the high-definition tool helped to reveal clearly OWC below the tool with greater confidence compared to the standard tool. The information from the high-definition tool, paired with the fluid identification offered from Neutron-Density and Neutron Near- Far count together were essential for an accurate landing. The usage of reservoir scale mapping technology in the horizontal section revealed the tilted OWC and reservoir structure at the same time, which allowed the team to achieve the required minimum production length while maintaining required standoff from the OWC. All wells were geosteered successfully with the accomplishment of placing the trajectories in optimum positions despite having a tight TVD window.
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
Abstract Objectives/Scope This paper provides an overview of design, operation, and maintenance of Subsea High Integrity Pressure Protection System (HIPPS) and Subsea Automated Pig Launcher (SAPL) in a shallow water gas condensate field development offshore Sarawak, Malaysia. It will outline the key technical drivers for the subsea field architecture development and technology qualification programme that was undertaken to manage the risk and uncertainties with deployment and operation of new subsea technology. Methods, Procedures, Process The shallow water field hereby denotes as "Field K" is located approximately 200 km offshore Sarawak, Malaysia at water depth of around 80 meter. The field consists of two (2) subsea wells and is expected to deliver non-associated gas at rate of 200 MMscf/d to a Central Processing Platform (CPP), located approximately 5 km away from the wells. The field was initially planned to be developed using a wellhead platform but mid-way through the project, it was decided for Field K to be developed using Subsea Production System (SPS) with the following key requirements: - Meet production target of 200 MMscf/d Achieve production availability of 96% Diverless philosophy throughout the field life Utilize the procured 24 inch Carbon Steel (CS) pipeline with design pressure of 83 barg Implement safety protection system that complies to Safety Integrity Level (SIL) 4 requirement to safeguard downstream facilities from the wells Closed in Tubing Head Pressure (CITHP) of 240 barg. Operational pigging to be carried out every 3 months and intelligent pigging every five (5) year for the 24 inch CS pipeline Any new technology to be implemented shall reach minimum Technology Readiness Level (TRL) 5 as per API 17N prior to its installation. Results, Observations, Conclusions A subsea technology screening and gap assessment was performed using API 17N and Company Internal Standards, and it was decided for the field to be developed using two 7 in. horizontal subsea tree, with two unit of Subsea HIPPS on manifold and retrievable Subsea Automated Pig Launcher at Pipeline End Termination (PLET). The field commenced its operation in December 2012 and was able to meet all the field key requirements identified. It was also the first subsea shallow water field that was designed, build, and operated by the Company. The paper will also highlight the key lessons learned and best practices during design, operation and maintenance that can be shared with other Operators and Industry. Novel/Additive Information The paper will outline the design, operational consideration, and necessary technology qualification program for new/modified subsea technology i.e., Subsea HIPPS and Subsea Automated Pig Launcher prior to deployment.
- North America > United States > Texas > Fort Worth Basin > Overall Field (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 199 > Block 6506/11 > Kristin Field > Tofte Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 199 > Block 6506/11 > Kristin Field > Ile Formation (0.99)
- (10 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems > Subsea production equipment (1.00)
- Facilities Design, Construction and Operation > Facilities Operations > Pipeline pigging (1.00)
Abstract The estimation of recoverable hydrocarbons, or field recovery factor (RF), is a critical process for Oil and Gas (O&G) companies to plan and optimise field development, manage ongoing production and identify profitable investments amongst other technical and commercial decisions. However, RF remains one of the greatest uncertainties in O&G projects. The difficulty in RF prediction arises due to the number of variables affecting the recovery from a reservoir. These includes variables that are both uncertain and beyond the control of O&G operators, such as fluid flow in microscopic pores, as a function of fluid and rock properties, and variables which are engineering design based, such as completion methods, secondary and tertiary recovery mechanisms. In early field life, insufficient production data coupled with subsurface uncertainty makes RF prediction uncertain, and it is often the experience of the operator combined with analogue studies that is used to determine RF. However, there may be instances where operators may have insufficient data from analogue fields to properly capture the uncertainty in the RF range. Utilising techniques of big data manipulation and machine learning (ML), two open-source, United States based data sets are (a) deconstructed to identify the key variables impacting the ultimate recovery of a field, and (b) used to create a ML model to predict the RF based on these key variables. These two datasets (the onshore Tertiary Oil Recovery System (TORIS), and the offshore Gulf of Mexico (GOM)) consist of over 1,000,000 real world data points. Employing a low code environment, we test the predictive ability of 20 different ML algorithms by comparing predictive error. Decision tree type models (Random Forest and Category Boosting) show the best results. The paper shows comparison to a distance based (K Neighbour) model as well. The work aims to show that not all variables influence RF equally and that any ML model should therefore be built with variables that have the greatest influence on RF yet have the lowest pairwise correlation. The influence of these input variables differs, depending on the implemented ML model. The paper demonstrates the predictive ability of ML models is strongly dependent on the input dataset. Predicting the recovery factor of fields within the TORIS and GOM databases, the R values are 0.81 and 0.88 respectively. Testing the algorithm on three additional fields outside of the two datasets, and in different geological provinces showed errors of up to 10-15%.
- North America > United States (1.00)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
- Geology > Sedimentary Geology (0.46)
- Geology > Geological Subdiscipline (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.94)
Fines Migration and Production in CSG Reservoirs: Laboratory & Modelling Study
Hashemi, Abolfazl (University of Adelaide) | Borazjani, Sara (University of Adelaide) | Nguyen, Cuong (University of Adelaide) | Loi, Grace (University of Adelaide) | Badalyan, Alexander (University of Adelaide) | Dang-Le, Bryant (University of Adelaide) | Bedrikovetsky, Pavel (University of Adelaide)
Abstract Fines detachment is an important component of methane production from Coal Bed Methane reservoirs. Production of coal fines is widely observed during dewatering and simultaneous gas-water production. The theory for fines detachment by drag against electrostatic attraction, model of the transport of those detrital fines, and their validation by laboratory test is widely used for planning and design of Coal Seam Gas developments. However, clay particles that naturally grow on coal grains and asperous parts of coal surfaces (authigenic and potential coal fines) are detached by breakage. To the best of our knowledge, the analytical theory for detachment of authigenic and potential coal fines is not available. The present paper fills the gap. Based on Timoshenko's beam theory, we derive failure conditions for breakage of authigenic and potential coal fines of the rock surface. It allows defining maximum retention function for fines breakage. The maximum retention is incorporated into transport equation of mobilized fines, allowing developing analytical models for linear flow of core flooding and radial flow of well inflow performance. Matching of laboratory coreflood data from four laboratory studies show high agreement. The model coefficients obtained by treatment of laboratory data allow predicting skin growth in production wells under fines migration.
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (1.00)
- Geology > Mineral (1.00)
- Asia > China > Xinjiang Uyghur Autonomous Region > Tarim Basin (0.99)
- Asia > China > Shanxi > Ordos Basin (0.99)
- Asia > China > Shaanxi > Ordos Basin (0.99)
- Asia > China > Gansu > Ordos Basin (0.99)