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Collaborating Authors
H2S management
Due to the severe and rapid corrosion of metallic equipment by strong acids at high temperatures, a high concentration of acidizing corrosion inhibitors (ACIs) is required during acidizing processes. There is always a need to develop more effective and environmentally friendly ACIs than current products. In this work, a highly effective ACI obtained from a novel main component and its synergistic effect with paraformaldehyde (PFA) and potassium iodide (KI) is presented. The ACI was prepared from the crude product of benzyl quinolinium chloride derivative (BQD) synthesized from benzyl chloride and quinoline in a simple way. The new ACI formulation, named "synergistic indolizine derivative mixture" (SIDM), which consists of BQD, PFA, and KI, showed superior corrosion inhibition effectiveness and temperature stability compared with commercially available ACI.
The paper presentation shows the application of a holistic approach to corrosion prediction that overcomes classical pitfalls in corrosion testing and modelling at high pressure, high temperature, and high CO2 conditions. Thermodynamic modelling of field and lab conditions allows for more accurate predictions by a novel CO2/H2S general corrosion model validated by laboratory tests. The results from the model and tests extend the application of selected stainless steel grade beyond the threshold conditions calculated by simplistic models and guidelines. In the case study used to showcase the workflow, conventional stainless steel is validated for most of the tubing. Harsh environments pose a challenge to the application of conventional steel materials.
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
The recent significant influx of large amounts of government incentives for a variety of green initiatives including CCS and CCUS has created a rush to drill and complete CO2 injection wells. However, the necessary corrosion data to make informed choices for corrosion resistance in these wells is minimal at best. Some oil and gas professionals have argued that there is no difference between the more than 40 years of petroleum experience with CO2 EOR and planned CCS wells. This comparison is not a valid one and can be risky considering the need for very long-term containment of CO2 required by regulators. This article presents a comparison between CO2 EOR and CCS for injection well metallurgy and explains why this comparison is invalid.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.33)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Mission Canyon Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Madison Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Forbisher Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Charles Formation:Middale Formation (0.99)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- (3 more...)
Sour-Rated 10,000-psi System High-Temperature Gas Development Wells: Sustaining the Malaysian National Gas Supply Through a Journey of Optimization in North Malay Basin
Jong, Siaw Chuan (Hess Exploration and Production Malaysia B.V. (Corresponding author)) | Aziz, Khairil Faiz Abdul (Hess Exploration and Production Malaysia B.V.) | Goo, Jia Jun (Hess Exploration and Production Malaysia B.V.) | Hiew, Ronnie (Hess Exploration and Production Malaysia B.V.) | Strickland, Kenny (Hess Exploration and Production Malaysia B.V.) | Hussin, Arief (Hess Exploration and Production Malaysia B.V.) | Yusof, Khazimad (Hess Exploration and Production Malaysia B.V.) | Macleod, Andy (Hess Exploration and Production Malaysia B.V.) | Yusoff, Syukur (Hess Exploration and Production Malaysia B.V.) | Chung, Chay Yoeng (Hess Exploration and Production Malaysia B.V.) | Liew, Alex (Hess Exploration and Production Malaysia B.V.)
Summary High temperature (HT), high carbon dioxide (CO2) coupled with hydrogen sulfide (H2S) contents, and rapid pore pressure fracture gradient (PPFG) pressure ramp increase in gas development wells can lead to significant capital expenditures for operators. Such wells typically need high corrosion resistance alloy material with at least a 10,000-psi (10-ksi)-rated system to complete. The deep reservoirs of the North Malay Basin, offshore peninsular Malaysia, also fall into the described category. In this paper, we aim to share the optimization journey, applications, and learnings of the company’s HT sour-rated 10-ksi gas development wells through several phases, besides fulfilling the gas delivery need for the country. In addition, we identify engineering and operational optimizations to reduce the well’s time and cost while upholding the safety of the crew as a top priority. The sour-rated HT gas development campaign for the company began in the year 2017, followed by a second campaign in the year 2018. Our focus centers on the third campaign, which concluded in the year 2022. A total of four, three, and four wells were drilled and completed in the first, second, and third campaigns respectively. The company’s wells engineering team applied Lean methodologies that covered the entire Plan-Do-Check-Adjust cycle to achieve optimization. Using well data, learning from experiences, working together, maintaining consistency, and pursuing ongoing enhancements are the main factors that ensure positive optimization outcomes. Fit-for-purpose drilling and completions equipment design and application, rig offline capabilities planning, wellhead dummy hanger plug design for offline cementing, intervention-less production packer setting device, offline annulus nitrogen cushion fluids displacement, and other applications will be explained in the paper. In this paper, we describe the operational challenges faced and outline the applied optimizations that led to significant improvements in the well performance compared with targets and previous campaigns. The optimization efforts by the wells team extended from the engineering phase to the execution stage, including the use of in-house digital capabilities to monitor well performance, in alignment with industry practice. The recent campaign post-optimization concluded with no safety incidents, average per well more than 48 days ahead with 39% lower cost than previous campaigns, average of 5.6% overall well nonproductive time (NPT), and achieved first gas to meet the country’s power generation demand. Furthermore, the motivating optimization results also coupled with 25% more production results compared with the prognosed. The positive results of this optimization journey were significantly influenced by transparent, collaborative, and proactive communication across different departments.
- Asia > Malaysia > South China Sea (0.61)
- Asia > Malaysia > Kelantan > South China Sea > Gulf of Thailand (0.61)
Underbalanced Coiled Tubing Drilling: Delivering Well Production Safely in High H2S and Tight Gas Reservoirs, UAE
Khan, Rao Shafin Ali (SLB (Corresponding author)) | Molero, Nestor (SLB) | Alam, Shah Sameer (SLB) | Mishael, Mohammad Basim (SLB) | Basha, Maged (SLB) | Zia, Arslan (SLB) | Zhylkaidarova, Sholpan (SLB) | Abd El-Meguid, Mohamed Osama (ADNOC Onshore) | Al Ali, Abdulrahman Hasan (ADNOC Onshore) | Saleh, Abdalla (ADNOC Onshore) | Almazrouei, Saeed Mohamed (ADNOC Onshore) | El Shahat, Ayman (ADNOC Onshore) | Bin Sumaida, Ali Sulaiman (ADNOC Onshore) | Al Mutawa, Ahmed Abdulla (ADNOC Onshore) | Yousfi, Fawad Zain (ADNOC Onshore) | Almteiri, Nama Ali (ADNOC Onshore) | Baslaib, Mohamed Ahmed (ADNOC Onshore) | Mantilla, Alfonso (ADNOC Upstream) | Ladmia, Abdelhak (ADNOC Upstream)
Summary United Arab Emirates (UAE) is seeking to become self-sufficient in gas supply by 2030. This has led the country to initiate several exploratory and appraisal projects to achieve this goal. This study covers one such pilot project targeting production from tight gas reservoirs in three wells through a coiled-tubing (CT) underbalanced drilling (UBD) project in ADNOC Onshore. CT pressure control equipment (PCE) was rigged up on top of production trees with wells already completed and cemented. A CT tower was used to accommodate the drilling bottomhole assembly (BHA) and eliminate risks related to its deployment. CT strings were designed to reach target intervals with sufficient weight on bit (WOB), suitable for sour environments, and able to withstand high pumping rates with mild circulating pressures. To address the hazards of H2S handling at the surface, a custom-fit closed-loop system was deployed. The recovered water was treated on the surface and reused for drilling to decrease the water consumption throughout the operations. The plan was to drill 3 3/4-in. horizontal laterals in all candidate wells. Each well was completed with a combination of a 4 1/2-in. and a 5 1/2-in. tubing and a 7-in. liner. Five laterals were drilled across the three candidate wells targeting carbonate reservoirs with each lateral having an average length of ~4,000 ft. The achieved rates of penetration varied significantly from 15 ft/min to 30 ft/min while drilling through the various formations. Over the course of the pilot project, several challenges had to be addressed, such as material accretion on the CT string during wiper trips, treatment of return fluids having high H2S content and rock cuttings, and ensuring the integrity of the CT pipe while operating in severe downhole environments. Solutions and lessons learned from each well were implemented subsequently in the campaign, such as the use of increased concentrations of H2S inhibitor to coat the CT string, the use of nitrified fluids based on changing well parameters to maintain underbalance, thorough pipe management through real-time CT inspection, and adding a fixed quantity of fresh water to the drilling system every day to avoid chemical reactions between the drilling fluid additives and hydrocarbons. The wells completed with this method exceeded production expectations by 35–50% across the project while reconfirming the value of the technology. The use of CT for UBD is still considered a challenging intervention worldwide. Such cases in high H2S environments are rare. This study outlines best practices for a CT UBD and a setup that can be replicated in other locations to implement this methodology with high H2S and when rig sourcing is a concern.
Hydrogen sulfide (H2S) production has in recent years become a mounting issue facing operators and midstream companies in major US basins. At present, H2S production appears to be random and poorly understood. As such, H2S is considered by many to be an unpreventable nuisance and one that is largely addressed by treating the dangerous gas at surface before putting it to a sales line. This article highlights impacts of H2S, possible sources, and a successful case study of a completions operation designed specifically to prevent H2S production in North Dakota's Williston Basin. H2S is a colorless gas known for its pungent "rotten egg" odor at low concentrations.
- North America > United States > South Dakota > Williston Basin (0.99)
- North America > United States > North Dakota > Williston Basin (0.99)
- North America > United States > Montana > Williston Basin (0.99)
Abstract An operator, while designing their completion, needed to secure slim electrical-line intervention technologies, including shifting, debris removal, and milling services. Environmental challenges dictated the following requirements for intervention: 28,5000-psi pressure rating, 150°C temperature, 2.313-in. pass-through restriction, and sour service (H2S rating) as required by the operator. No slim electrical-line intervention technologies existed that met the sour high-H2S, high-pressure, small pass-through restriction requirements. However, upgrading an existing 20,000-psi slim electrical-line instrumented and automated intervention platform was an economical and technically feasible option that would meet the operator's requirements. The slim high-H2S and high-pressure upgrade was achieved by improving the pressure rating of critical components through a combination of using high-performance materials and optimizing the mechanical robustness by removing high-pressure stress concentrations. Functional and environmental tests were completed to validate the solution. This paper presents the analysis and development done to arrive at this solution, demonstrating how a flexible intervention architecture can be upgraded to expand its performance capabilities. The solution also enables future possibilities of expanding the platform to additional services such as tubing cutting and restriction navigation at pressures up to 28,500 psi.
Abstract High sour fields beyond 10% H2S concentration are considered one of the severe environments that require suitable tubular components and accessories in upstream environment to ensure sustainable production. Such environments represent a challenging operating envelop where durability and safety are the top concerns due to higher H2S concentration at a higher partial pressure and higher temperature (HPHT). The risk is amplified for the wells with higher than 10% H2S concentration, namely the High H2S wells, and those exceeding 25% H2S concentration which are typically labeled as Ultra-High H2S wells. Corrosion in gas operations can be aggravated in downhole where high H2S at higher temperatures pose additional challenges. Selection of proper material to ensure a sustainable well condition is one of the important elements for the development of these HPHT gas wells. Various challenges were identified, including the selection of cost-effective material which is capable of withstanding short and long term H2S and CO2 partial pressures as well as control generalized CO2 corrosion, sulfide stress cracking (SSC), and stress-oriented hydrogen induced cracking (SOHIC). With the advancement of Non-Metallics (NM) materials in several applications across the O&G sector, it holds a promise to provide an alternative material solution in lieu of CRA alloy material for the HPHT downhole applications. NM materials are lightweight and they can be designed to withstand higher strength capability in addition to their outstanding corrosion resistance properties in a high H2S environment. Moreover, they can be engineered to fulfill the intended application due to their high design flexibility and durability. In the downhole applications, there is a number of NM products that have been implemented in sour environments, including sealants as well as downhole accessories and tools, where the list of NM technologies is considerably growing. This paper highlights the concept of using NM products such as coiled tubulars, pressure control equipment and elastomers as well as the challenges on the development and deployment of these key components in high sour fields.
- Asia > Middle East > UAE (0.29)
- Asia > Middle East > Saudi Arabia (0.28)
Performance Results from the Installation of High Temperature Reinforced Thermoplastic Pipes (RTP) in Sour Gas Lines in Abu Dhabi
Tamimi, Abdallah (ADNOC) | Wright, John R (Specialty RTP Inc) | Lemock, Gabriel (Specialty RTP Inc) | Al Alawi, Faisal Masoud (ADNOC) | Rodriguez, Clemente (Total Energies) | Burke, Raymond (ADNOC)
Abstract Reinforced thermoplastic pipe (RTP) has historically been used for water injection and disposal pipelines in the Middle East for processes at operating temperatures up to 85°C. As the acceptance of RTP pipelines has increased in the region, applications for pipelines utilizing RTP has grown, but generally in lower temperature applications. Three sections of RTP were installed in a flow line in Abu Dhabi for high temperature (110°C) flow. The RTP was designed for operating temperatures to 110°C for high H2S (10% -20%) and CO2 natural gas flow lines, which also contained brine and sand. The sections of pipe were removed after four months in service and key performance tests were performed. The results were compared with un-aged samples. This paper provides an overview of the RTP pipe design, installation and removal, performance tests and conclusions regarding the comparison of test results between aged and unaged RTP pipes. Additional testing suggestions are proposed on the basis of changes in flowline operating parameters over time.
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers (1.00)
Abstract Non-metallic pipe systems are the perfect option for transporting highly corrosive fluids from oil and gas production which are potentially environmentally hazardous, since they contain volatile organic hydrocarbons. The operation of oil and gas production in agricultural lands is common in Europe and requires permeation tight solutions in order to prevent any kind of environmental contamination. In the past, leakages caused by corrosion damages on carbon steel pipes or by permeation of hydrocarbons through pipes made of high-density polyethylene (HDPE) have resulted in environmental damages. In order to prove the suitability of plastic pipes with an integrated aluminum barrier layer tests over a 4-year time period were done in the context of field- and laboratory trials. For the pilot tests performed in a crude oil production system, the oil and water composition was given by the real case. For the systematic laboratory tests, clearly specified test liquids which came as close to providing a representative sample as possible were used. In order to simulate the most severe conditions conceivable, the test liquids were a saturated solution consisting of various volatile hydrocarbons, some of them also chlorinated, and a mixture of pure volatile hydrocarbons with a 10-per-cent share of aromatic toluene. In contrast to single-layer plastic pipes, the pipes featuring a barrier layer were shown to be resistant to permeation of all of the dissolved volatile organic ingredients examined by the tests. These results could be confirmed by the performed pilot test in Romania. Thus, plastic pipes equipped with a metallic barrier layer can be recommended for loss-free transport of aqueous liquids containing hydrocarbons, such as production water in crude oil. Combined with permanent monitoring for the purpose of damage detection, this non-metallic pipe solution complies with even the strictest environmental requirements, thus enabling oil production in environmental sensitive areas and guarantees reliable protection of the environment.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Health, Safety, Environment & Sustainability > Environment > Waste management (0.94)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (0.68)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (0.68)