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Collaborating Authors
International Petroleum Technology Conference
Abstract Unloading wells post drilling and completion is critical in ensuring risk of well productivity impairment due to extended residence of drilling and completion fluids in the well is minimized. In addition, unloading high pressure (HHP) gas wells can be quite complex since it includes rapid changes in operating conditions (pressure, temperatures and rates), which if not planned properly, can lead to exceeding design operating envelopes and in the worst-case result in process safety incidents. The objective of this paper is to present a case study, which demonstrates the application of transient flow modelling for analysis of complex high pressure (HHP) gas well unloading. Traditional well and surface network modelling tools and softwares use steady state flow models. However, well unloading is a transient phenomenon with rapid changes in pressure, temperature, flowrate and hold-up and ideally requires multiphase transient flow modelling software to predict the conditions accurately. This paper describes how transient flow simulation, using the software package OLGA, was applied to model well unloading with the objective to keep the flow within the operating envelope of the well and surface equipment. The execution was carried out safely and successfully aided by the modelling work carried out in OLGA. A comparison of the modelled and actual measured parameters is presented showcasing the utility of transient flow modelling in planning, decision making and smooth execution. The model was used to optimize the choke positions within the constraints of low temperature limit, while avoiding the requirement of heat exchangers, steam generators and flare stack and avoid a long learning curve during execution. This also ensured that flaring was not required which means no Greenhouse Gas (GHG) emissions and the produced hydrocarbons were monetized.
A Breakthrough Solution to Set ESP Packer at Higher Inclination by a Creative Combination of Re-Designing Slick-Line Tool String, Completion String and Well Trajectory Saving up to 30% of Completion Time in a Middle East Depleted Oil Field.
Almuallim, Mustafa (SLB) | Ullah, Syed Zahoor (SLB) | Ruzhnikov, Alexey (SLB) | Silva, Paul (SLB) | Al Shaikh, Jaffar (SLB) | Agarwal, Rohit (SLB) | Al-Herz, Mohammad (SLB)
Abstract After years of oil production in the Middle East, conventional electric submersible pump (ESP) placement at inclination of 45° is no longer deep enough to enable inflow of hydrocarbons. As a result, in some fields a packer placement is pushed deeper and closer to a reservoir at 55°-70° inclination which negatively impacts the ability to set packer with conventionally slick-line run plug system. The paper provides information on technologies used to overcome challenges associated by use of creative solution of modified slick-line run tubing plug system aiming to set the production packers at high inclination, in excess of 45°. This optimized system eliminates risk of weakened slickline jarring action across deviated wellbore by optimizing landing plug design, completion string configuration and landing profile criteria at which plug is deployed to pressurize tubing and set completion packer. The manuscript discusses torque and drag modeling utilized to plan and monitor deployment of modified slick-line system across high deviated and extended reach (ERD) wells. Finally, paper concludes with a detailed deployment BHA, execution road map and contingencies. The abovementioned system was successfully implemented across 5 extended reach wells (ERD) with packer set at an inclination up to 70°. Revised approached enabled optimization of both slick-line BHA and completion string such, that cost is reduced by over 30% compared to other wells where packer was set with conventional approaches like coiled tubing and wireline tractor. Furthermore, time associated with completion operation has been reduced by more than 2 days. Utilized model of slick-line deployment is currently adopted by the operator as standard practice to set ESP packer across highly deviated trajectories for both multi- and single lateral extended reach oil wells. The document provides a novel approach to set production packer at high inclination by utilization of optimized deployment BHA comparing to more expensive and time-consuming alternative approaches. It also provides technical feasibility analysis for slickline deployment into wellbores of high inclination. The proposed approach can be implemented any project worldwide to optimize both wireline and slick-line operation and thereby improving the performance.
- North America > United States > Texas (0.28)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.15)
Abstract In a deep gas wells drilling project, due to surface location limitations, predetermined target, and completion requirements, an S shape well profile is required. The well type is one of the most challenging due to the extended tangent section, increasing the risk of differential sticking, hole cleaning, extended reaming while tripping, and losses risk from the fracture-prone formation. An aggressive target at the outmost reservoir boundary is determined, requiring delivery of the furthest step-out S shape well, demanding more advanced technology and rigorous well planning. Comprehensive well planning and strategy, utilizing cutting-edge technology to achieve the furthest step-out S shape well. –Thorough offset wells analysis, identifying best drilling practices for the most critical S shape directional section. –Modified S shape well design, dividing two directional sections to enable reaching desired reservoir target. –Latest generation of RSS technology with a more robust system and improved tool reliability, enabling the achievement of required DLS in high drilling dynamic conditions. –Optimized BHA design, improved drilling fluid design, and LCM strategy, enabling the achievement of maximum drilling parameters while minimizing differential sticking and losses risk. –Specific casing and light cementing design strategy in the extensive S shape section allowing the casing to reach the bottom smoothly and avoid losses risk while cementing due to higher ECD. High drilling performance was achieved within the S shape well type in the field with no downhole tool failure nor drilling complexity and meeting desired well trajectory. High losses risk in the section and differential sticking was avoided, ensuring close adherence to drilling fluid parameters with bridge and seal strategy while drilling. The determined reservoir target was successfully reached with a total horizontal displacement of 3,140 ft (~1 km), resulting in the longest step-out S shape well in the deep gas well project. No wiper trip was required prior to running casing following best drilling practices and drilling fluid design and strategy prior to POOH the BHA. The casing string was able to run smoothly in the field's longest open hole section, with less than maximum rig hoisting capacity, following low drag friction factor to the casing point. The cementing job was performed using a real-time top of cement identifier and was further performed successfully without inducing any losses using a light slurry strategy and met the objective to seal off the reservoir formation. The novel holistic strategy encompasses cutting-edge technology utilization, Innovative well construction design, optimized BHA and drilling strategy, drilling fluid strategy, and specific measures in the casing and cementing design and execution, resulting in successfully delivering the longest step-out S Shape well in a deep gas drilling project. Collaboration from a team consisting of multi-technical expertise is also crucial to efficiently design and execute the work, leading to successful well delivery.
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Tengiz Formation (0.99)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Korolev Formation (0.99)
- Well Drilling > Well Planning > Trajectory design (1.00)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drillstring Design > Drill pipe selection (1.00)
- (6 more...)
Abstract Kinetic hydrate inhibitors (KHIs) and anti-agglomerants (AAs) – known as low dosage hydrate inhibitors (LDHIs) – have been used widely for gas hydrate prevention in oil and gas operations. They offer significant advantages over thermodynamic inhibitors (e.g., methanol and glycols). While significant works have been done on KHIs evaluation, AAs suffer from their evaluation in terms of hydrate structural effect, gas composition, water cut, and hydrate amount, which are the main objectives of this work. A Shut-in-Restart procedure was carried out to experimentally evaluate (using a visual rocking cell) various commercial AAs in different gas compositions (from a simple methane system to multicomponent natural gas systems). The kinetics of hydrate growth rate and the amount of hydrate formation in the presence of AAs were also analysed using the recorded pressure-temperature data. The amount of hydrate formation (WCH: percentage of water converted to hydrate) was also calculated by pressure drop and establishing the pressure-temperature hydrate flash. The experimental results from the step heating equilibrium point measurement suggest the formation of multiple hydrate structures or phases in order of thermodynamic stability rather than the formation of simple structure II hydrate in the multicomponent natural gas system. The initial findings of experimental studies show that the performance of AAs is not identical for different gas compositions. This is potentially due to the hydrate structural effect on AAs performance. For example, while a commercially available AA (as tested here) could not prevent hydrate agglomeration/blockage in the methane system (plugging occurred after 2% hydrate formed in the system), it showed a much better performance in the natural gas systems. In addition, while hydrate plugging was not observed in the visual rocking cell in the rich natural gas system with AA (at a high subcooling temperature of ∼15°C), some hydrate agglomeration and hydrate plugging were observed for the lean natural gas system at the same subcooling temperature. It is speculated that methane hydrate structure I is potentially the main reason for hydrate plugging and failure of AAs. Finally, the results indicate that water cut%, gas composition, and AAs concentration have a significant effect on hydrate growth rate and hydrate plugging. In addition to increasing confidence in AAs field use, findings potentially have novel applications with respect to hydrate structural effect on plugging and hydrate plug calculation. A robust pressure-temperature hydrate flash calculation is required to calculate the percent of water converted to hydrate during hydrate growth in the presence of AAs.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
Abstract Acid matrix stimulation is a widely used method to improve well productivity by removing and/or bypassing damage in the near wellbore area and creating channels for hydrocarbon flow. Hydrochloric (HCl) and organic acids are commonly used to design fluid recipes utilized in these treatments. However, these acids can cause formation damage by forming stable emulsions and sludge upon contact with formation crude if the treatment and/or stimulation fluid are not designed carefully. It is well reported that acid in contact with crude oil can destabilize asphaltenes either by neutralizing asphaltene or dissolution of resins. Therefore, acid recipe chemical additives must be selected and examined carefully to ensure effective acidizing treatments. In this study, the interaction of different HCl-based recipes with oil was investigated using different lab techniques and analysis including acid/oil separation tests, sludging tendency testing, and SARA analysis. The influence of several factors including acid concentration, acid type, and dissolved iron content were investigated. Experiments were conducted with varying acid blends, demulsifier and anti-sludge type and concentration. To simulate dissolving corrosion products by acids in downhole environment, ferric chloride was incorporated in acid recipes. The results showed an increase in temperature enhanced emulsion/sludge breaking tendency. The addition of demulsifier/anti-sludge agents in acid recipes was necessary to avoid creating stable emulsions and sludge that can damage reservoir permeability. Higher amounts of dissolved iron in the acid solution resulted in a more stable emulsion and enhanced sludge formation. Asphaltene problematic oil, as determined from the asphaltene colloidal instability index, showed severe sludging tendency. Lastly, the use of HCl/organic acid blends may be necessary for some oil types to avoid formation of sludge. This paper showcases a comprehensive testing method to mitigate formation damage from acidizing treatments. The testing can be expanded to design an acid stimulation fluid recipe to minimize acid-induced formation damage and maximize well productivity enhancement.
- Asia > Middle East (0.69)
- North America > United States > Louisiana (0.28)
- North America > United States > Texas (0.28)
- North America > Canada > Ontario (0.28)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Overcoming Challenges of Polymer Injection Pilot in High-viscosity, High-salinity Reservoir – A Case Study from Sirikit Oilfield, Thailand
Worawutthichanyakul, Thanawut (PTTEP) | Hanchaiphiboolkul, Suwapich (PTTEP) | Ketmalee, Thanapong (PTTEP) | Pancharoen, Monrawee (PTTEP) | Sinhabaedya, Prangtip (PTTEP) | Thammasanya, Rungkarn (PTTEP) | Rujipimolkit, Chuthanart (PTTEP) | Srisuriyon, Jantakan (PTTEP) | Roatkanjanaporn, Tiam (PTTEP) | Sornsoongnoen, Yannavit (PTTEP) | Srisen, Parichat (PTTEP)
Abstract In Pru Kratium (PKM) highly viscous oil reservoir, the secondary recovery method such as waterflood can adversely affect production due to an unfavorable mobility ratio, resulting in viscous fingering and early water breakthrough. Although polymer flooding which usually mitigates unfavorable mobility ratio, this technique also faces a challenge due to the high salinity formation water which may lead to excessive polymer consumption. To improve recovery, a special polymer injection scheme was designed and the small-scale pilot was initiated. After one year of injection, the pilot demonstrated that the polymer improved the sweep efficiency of the flood in both vertical and horizontal directions. Ultimately, the increase in oil recovery factor gain was 2.41%.
- Geology > Geological Subdiscipline (0.48)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (5 more...)
Abstract To support the Company direction of GHG emission reduction in PTTEP operation, GBS, APEX and OMI have initiated fuel optimization to minimize fuel gas consumption. Over 80% of total fuel gas consumption is fed to Turbo Compressor to convert mechanical power to gas energy by compression system. To improve overall efficiency of fuel consumption, the whole gas compression process has been reviewed and analyzed. From preliminary review, there is a room to improve efficiency in part of gas cooling gas treatment process equipped with JT valve (Joule-Thomson, pressure reducing valve) that requires inlet pressure about 63-65 barg and outlet pressure of 55 barg to have cooling effect that decreases gas temperature from 45°C to 25°C. This cooling method takes huge energy from gas compressed in previous system. To improve overall process efficiency, the whole gas compression and cooling system was reviewed thoroughly. Consequently, it was found that the cooling margin of upstream equipment can compensate some cooling effect of JT valve leading to energy optimization of gas compression system without any additional modification and investment. After process tuning with the margin of Booster Compressor Discharge Cooler and Wet Gas / Gas Liquid Heat Exchanger upstream of JT valve, the required inlet pressure of JT valve can be reduced that leads to Booster Compressor discharge pressure declined from 64 barg to 61 barg while JT valve outlet temperature is still maintained at of 25°C as design condition without changing any other related operating condition of the systems before process tuning. The lower pressure of compressor discharge, the lesser fuel gas consumption is expected for energy transformation of compression system.
Insights on the Origin and Distribution of CO2 in Malay Basin, Offshore Peninsular Malaysia: A Petroleum System Modelling approach
Nayak, Satyabrata (PETRONAS) | Masoudi, Rahim (PETRONAS) | Tarang Patrick Panting, Alexander (PETRONAS) | B M Diah, M Amri (PETRONAS) | B Roslan, Mohd Razeif (PETRONAS) | B M Amin, M Farid (PETRONAS) | R Iyer, Subramania (Halliburton) | Aarssen, Ben Van (Halliburton) | Fun, Sook (Halliburton) | Mishra, Somen (Halliburton)
Abstract High concentration of CO2 in various fields of Malay basin, offshore Peninsular Malaysia pose major challenges in monetizing the resources in a sustainable way. Focused study to understand the source, origin and distribution of CO2 is essential to make informed decisions on developing the fields. This paper is part of the basin scale study to address the distribution of CO2 and its risk assessment. Modelling of the petroleum system including CO2 contaminant was adopted to validate the fluid accumulations in the basin with observed results from fields. An Earth Model was built using maps generated from an integrated study of seismic and 65 key wells. The depth to basement and depth to Moho were incorporated from previous gravity modelling study. The CO2 content and isotope data compiled from reports facilitated in building the knowledge on the source, origin, and distribution over the study area. Play segments identified based on tectonic features were used to divide the basin into subset areas for analysis.
- Asia > Malaysia > South China Sea > Malay Basin (0.99)
- Asia > China > South China Sea > Penyu Basin (0.99)
- North America > United States > Gulf of Mexico > Gulf Coast Basin (0.97)
- Europe > Norway (0.89)
Abstract Carbon capture and storage (CCS) presents a key solution to reducing emissions especially from stationary power and industrial sites. A major component of CCS is CO2 storage in geologic formations, including saline aquifers, presents a great opportunity for the oil and gas industry to capitalize on their subsurface expertise to ensure that CO2 is stored safely underground over the long term. Saline aquifers are particularly relevant in the Middle East, where hydrocarbon reservoirs may not be at high depletion stages and so may not be available for CO2 storage yet. This paper looks at key geologic formation considerations related to CO2 storage in saline aquifers, highlighting the static and dynamic characteristics of the rock and the fluids that determine how much CO2 can be stored and at what injection rate. It also highlights how these characteristics affect the economics of the subsurface component of a CCS project. This paper shall provide an overview of the key aspects that guide subsurface storage evaluations: containment ability, trapping mechanisms, storage capacity, and injectivity. It will highlight the different storage capacity assessment methods. Then it shall discuss resource classification and categorization, and determination of commerciality as per the SPE CO2 Storage Resources Management System (SRMS). Finally, the paper goes into further considerations that need to be taken into account beyond the initial screening, including the data acquisition program and the impact of CO2 stream impurities on storage potential, geologic formation properties and cap rock integrity. The work illustrates the importance of understanding the physics of CO2 injection into a water-bearing system and lays out considerations for screening potential saline aquifer sites from a reservoir engineering perspective. The screening process should evaluate the anticipated CO2 trapping mechanism, assure its ability to contain the injected fluids over the long term, and estimate its storage capacity and injectivity.
- Asia > Middle East (0.66)
- North America > United States > Texas (0.28)
- Geology > Petroleum Play Type (1.00)
- Geology > Rock Type > Sedimentary Rock (0.46)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- (2 more...)
Success Story of the Development of Extremely Low-BTU Flare Tip Technology
Assavanives, Boonyakorn (PTT Exploration and Production Public Company Limited) | Watanakun, Kantkanit (PTT Exploration and Production Public Company Limited) | Amarutanon, Nunthachai (PTT Exploration and Production Public Company Limited) | Kodesh, Zach (John Zink Hamworthy Combustion) | Muangsuankwan, Natthasart (PTT Exploration and Production Public Company Limited) | Watcharasing, Sunisa (PTT Exploration and Production Public Company Limited) | Sinthavarayan, Kanokporn (PTT Exploration and Production Public Company Limited)
Abstract Current low-BTU flare tip technologies require a flare gas lower heating value (LHV) of approximately 200 BTU/scf while significant advancement on CO2 removal membrane technology has resulted in an extremely low-BTU waste gases having LHVs around 140 BTU/scf. This requires the extremely lean waste gas to be supplemented with methane to raise its heating value to achieve stable combustion. Not only does the operator lose the benefit of the advanced membrane technology but they also lose product (sellable gas) and have increased green house gas (GHG) emissions at the production site. Consequently, the development of the "Extremely Low-BTU Flare Tip" is beneficial in multiple ways. The Extremely Low-BTU Flare Tip development project was launched as a joint research and development project between PTTEP and John Zink Hamworthy Combustion (JZHC). The innovative design is based on theories behind low heating value gas combustion and improves upon existing low-BTU flare technology. The goal was to obtain flame stability and safe operation in offshore oil and gas production environments at LHVs significantly lower than 200 BTU/scf. This project included multiple iterations of prototype design, simulation, and testing, with various parameter adjustments to optimize the performance against completeness of combustion criteria. The design was studied through computational fluid dynamics (CFD) simulation and prototype testing to develop the operating envelope of the Extremely Low-BTU Flare Tip. The design of the tip integrates John Zink's existing technology with additional components i.e. spokes and top hat. CFD simulation was performed to observe the fluid behaviors, including temperature, velocity, and unburned hydrocarbon; allowing modification of the design prior to the fabrication of the prototype. The final design has been proven by a series of prototype tests to reinforce the level of confidence in its performance and mechanical integrity. The test results show that the Extremely Low BTU Flare Tip has the capability to combust flare gases with an LHV as low as 110 Btu/scf which is a significant improvement over existing flare tip technology. The benefit of this technology is estimated to be between 10-31 MMUSD per year per platform, depending on the lowest achieved heating value. The success of the Extremely Low BTU flare tip development project provides a breakthrough technology which is not limited to brownfield applications but also supports future acquisition and development of Greenfield sites. This Extremely Low BTU flare tip technology will improve the probability of success for greenfield development with a high CO2 reservoir by maximizing reservoir recovery, optimizing overall capital and operational expenditure, and minimizing hydrocarbons flared which has the direct effect of increasing gas sales and decreasing greenhouse gas emissions.
- Asia > Thailand (0.92)
- North America > United States (0.69)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Thailand Government (0.52)