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Collaborating Authors
Production Chemistry
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, 150ยฐC 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 85ยฐC. 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 (110ยฐC) flow. The RTP was designed for operating temperatures to 110ยฐC 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)
Riserless Intervention on Deepwater Gulf of Mexico Well increases contributing interval length by 10-fold
Hosein, W. (BP America, Houston, Texas, United States) | Vick, M. (BP America, Houston, Texas, United States) | Quy, T. (BP America, Houston, Texas, United States) | Dada, M. (BP America, Houston, Texas, United States) | Sierra, J. (BP America, Houston, Texas, United States) | Cubides, J. (BP America, Houston, Texas, United States)
Abstract Well X is an oil producer in the Mississippi Canyon of the Gulf of Mexico. The well was originally designed as a smart downhole flow control (DHFC) completion that allowed split flow between two cased-hole frac-pack (CHFP) sand control completions. Unfortunately, the DHFC system failed, and the well must be produced with commingled flow from both zones. Over time the well's skin (frictional pressure loss across the completion screens) has increased to a point where the well's production rate needed to be reduced to limit erosion and maintain integrity of the completion. Well X receives pressure support from a downdip injector which has led to seawater production and introduced the risk of barium-sulfate scale. The well's previous scale prevention treatment expired at the end of 2022. The scope of the Riserless Light Well Intervention (RLWI) was to remediate skin and refresh the scale prevention treatment in both zones. The intervention required right scoping the well control and ancillary equipment to enable successful pumping and wireline operations on a sub-ambient well under elevated subsea and surface metocean conditions. Additionally, surveillance was necessary to assess damage and allocate contributions from each zone. Individual isolation of both zones was required for acid stimulation and scale treatment. Achieving this involved either setting plugs or installing isolation sleeves across the failed flow control device. Based on production logs, it was observed that the contributing interval of the lower zone had been reduced to about 10 ft despite having 110 ft of perforations. To address this, an acid stimulation with use of diverter pills was carried out on the lower zone which resulted in an increase in the contributing height to the full 110 ft, marking a greater than 10-fold increase. Furthermore, successful scale prevention treatments were administered to both zones to prevent barium sulfate scale deposition. Throughout the intervention, all wireline operations were carried out effectively under sub-ambient conditions without any hydrate problems, loss of well control, or seawater ingress. Acid stimulation bullheaded from surface aided in successfully treating non-contributing intervals with the use of diverter pills. The use of the collapse rated hoses along with other well control package modifications have enabled access to other sub-ambient wellwork in this field.
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)
Abstract This presentation will discuss how the existing corrosion resistant pipeline solutions measure against the performance characteristics required for safe and reliable corrosion-resistant pipelines in the oil and gas industry. This evaluation will survey the performance requirements of corrosion-resistant pipeline solutions considering technical, construction, economic and ESG (Environmental, Social and Governance) perspectives and will compare those requirements to the characteristics of the available corrosion-resistant pipeline systems. This presentation also includes a case study covering the use of an innovative factory lined carbon steel pipeline product in a produced water network for a global exploration and production company in the Rocky Mountain region of the USA. As the corrosion-resistant pipeline options are engineered systems that vary in construction, performance, economics and ESG characteristics, this presentation will highlight the advantages and disadvantages of the various corrosion-resistant pipeline options and will provide criteria for material selection in order to achieve safe and reliable corrosion-resistant pipelines within the oil and gas industry. This presentation will provide the pipelines professional with relevant considerations to support the decision-making process related to the material selection of corrosion-resistant pipelines.
- North America > United States (0.24)
- North America > Canada > British Columbia (0.24)
- North America > Canada > Alberta (0.24)
- Materials > Metals & Mining (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Midstream (1.00)
- Construction & Engineering (1.00)
Dissolver Treatments to Re-Instate Functionality of Subsurface Safety Valves in Water Injection Wells
Hatscher, S. T. (Wintershall Dea Norge AS) | Havrevoll, N. (Wintershall Dea Norge AS) | Herrmann, T. (Wintershall Dea Norge AS) | Gjersdal, S. (Wintershall Dea Norge AS) | Dzhuraev, D. (Wintershall Dea Norge AS) | Torsvik, M. (Wintershall Dea Norge AS)
Abstract The Downhole Safety Valve (DHSV) integrity tests of two water injection wells on the Nova subsea oil field on the Norwegian Continental Shelf failed after one month in operation. One of the two wells, W-1, also showed issues with the Injection Master Valve (IMV). The objective was to re-instate the functionality of all compromised valves as soon as possible. First, the root cause for the malfunction was to be identified. Several hypotheses were developed and assessed, including mechanical and chemical issues. Both injectors (W-1 and W-4) are completed in the oil leg of the reservoir and have been cleaned up to rig before an injection test was conducted. The wells were then suspended for several months prior to initial start-up and commencement of water injection. Although wax inhibition was used during the clean-up, wax deposition at DHSV depth could not be fully discarded. Monoethylene glycol (MEG) has been deployed for hydrate mitigation after the injection tests and during initial well start-up. Pressure data indicated that at least partially, a column inversion within the tubing, from water to hydrocarbons, occurred during the suspension period. This observation gave support to that wax or hydrate deposition might restrict the DHSVs' flappers' movement. Based on this hypothesis, an operation with an Inspection Maintenance and Repair (IMR) vessel was planned, organized and conducted within five weeks after the failed tests. The treatment concept included not only a wax dissolver, but also MEG and heated fluids to combine the benefits of temperature as well as chemical dissolution towards either potential type of deposit. Both wells were treated from the vessel as per plan. The operation successfully re-instated the functionality of all three compromised valves, allowing to safely commence water injection into the reservoir.
- North America > United States (0.47)
- Europe > Norway > North Sea (0.29)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.67)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 418 > Block 35/9 > Nova Field > Viking Formation > Heather Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 418 > Block 35/9 > Nova Field > Rannoch Formation > Heather Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 418 > Block 35/8 > Nova Field > Viking Formation > Heather Formation (0.99)
- (4 more...)
- Well Completion > Completion Selection and Design > Completion equipment (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (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 > Hydrates (0.86)
Abstract With increasing interest in non-metallic products for downhole applications, such as the fiberglass tubing, it is essential to ensure the well integrity in similar way as standard carbon steel completions. One important aspect of well integrity is the ability to routinely access the downhole condition of the tubing and perform basic intervention. This paper demonstrates the testing and validation of different mechanical evaluations of the integrity of fiberglass tubing using logging and intervention tools. In this work, two joints of Fiberglass were connected together in order to study the effect of logging and intervention tools on the integrity of these joints from inner and outer surfaces as well as the structural integrity. For inner wall evaluation, a multifinger caliper tool was run inside the two joints several times in order to investigate potential damage caused by the fingers. In addition, a tubing puncher was used to punch a hole and characterize the surface damage and any effects on the structural integrity of the fiberglass. Furthermore, a tubing cut was performed in order to confirm the performance of the cutting tool in such environment. All the tests were conducted safely and successfully at surface using two different sizes of fiberglass tubing. The tested tubulars were split cut to further investigate internal condition. The effect of applied fingertips on the inner wall surface of the fiberglass from several passes indicated minor scratches that can be further investigated using an accelerated wear test. The integrity of this non-metallic tubular can be evaluated using standard mechanical tools in order to identify defects and scale buildup. Other intervention tools such as the mechanical puncher and cutter indicated successful deployment under surface conditions. Investigation of existing downhole evaluation and intervention technologies can provide an immediate assessment of the benefits and limitations with respect to unconventional completions such as the fiberglass tubing and other non-metallic pipes. Future research and development programs can rely on such solid basis to tailor advanced solutions for any specific application or products.
Detection of Iron Disulfide Materials in Geological Porous Media Using Spectral Induced Polarization Method
Badhafere, D. (Department of Petroleum Engineering, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum & Minerals) | Kirmizakis, P. (Department of Geosciences, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum & Minerals (Corresponding author)) | Oshaish, A. (Department of Petroleum Engineering, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum & Minerals) | El-Husseiny, A. (Department of Geosciences, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum & Minerals) | Mahmoud, M. (Department of Petroleum Engineering, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum & Minerals) | Ntarlagiannis, D. (Department of Earth and Environmental Sciences, Rutgers University) | Soupios, P. (Department of Geosciences, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum & Minerals)
Summary Iron sulfide (FeS) scale is a known problem that can significantly impact oil and gas (O&G) production. However, current monitoring methods cannot detect the problem at early stages, not until it is too late for any meaningful remedial action. Spectral induced polarization (SIP) is an established geophysical method increasingly used in near-surface environmental applications. The unique characteristics of the SIP method, mainly the sensitivity to both bulk and interfacial properties of the medium, allow for the potential use as a characterization and monitoring tool. SIP is particularly sensitive to metallic targets, such as FeS, with direct implications for the detection, characterization, and quantification of FeS scale. In a column setup, various concentrations of pyrite (FeS2), a common form of FeS scale, within calcite were tested to examine the SIP sensitivity and establish qualitative and quantitative relationships between SIP signals and FeS2 properties. The concentration of FeS2 in the samples directly impacts the SIP signals; the higher the concentration, the higher the magnitude of SIP parameters. Specifically, the SIP method detected the FeS2 presence as low as 0.25% in the bulk volume of the tested sample. This study supports the potential use of SIP as a detection method of FeS2 presence. Furthermore, it paves the way for upcoming studies utilizing SIP as a reliable and robust FeS scale characterization and monitoring method.
- Europe (0.68)
- North America > United States (0.46)
- Asia > Middle East > Saudi Arabia (0.28)
Summary The stability of asphaltenes in crude oil is influenced by various factors, including interactions with reservoir components such as brine and rock formations. While previous research has focused on pressure and temperature effects, a comprehensive understanding of the combined impact of brine and reservoir rock on asphaltene stability is lacking. This study investigates the individual and combined influences of brine and rock formations on asphaltene stability. First, 11 crude oil samples from diverse locations were characterized using API gravity, viscosity, and saturates, aromatics, resins, and asphaltenes (SARA) fraction analysis. The elemental composition of the crude oils, including carbon, hydrogen, nitrogen, and various metals, was determined. The surface properties of asphaltenes were analyzed using scanning electron microscopy coupled with energy-dispersive X-ray spectroscopy (SEM-EDS). The interaction between asphaltenes and deionized water was examined through zeta potential, particle size, conductivity, and pH measurements. The behavior of asphaltenes in an 8,000 ppm NaCl solution was also investigated. The SEM analysis revealed the presence of inorganic content on the surfaces of asphaltenes, indicating interactions between asphaltenes and reservoir rock. A strong correlation between the zeta potential and sulfur content of asphaltenes was observed, highlighting the influence of sulfur compounds on surface charge and stability in heavy crudes. Additionally, the correlation between total dissolved solids (TDS) content and alkaline Earth metals and alkali metals in asphaltenes confirmed interactions between asphaltenes and reservoir brine. This interaction is likely influenced by the composition and properties of both the brine and reservoir rock. The presence of electrical charges on the asphaltene surfaces, as determined by zeta potential measurements, further supports the role of electrostatic interactions in asphaltene stability. The low precipitation tendency observed for most asphaltene samples, coupled with the abundance of negatively charged particles, underscores the importance of electrical charges in controlling stability. This study provides novel insights into asphaltene stability, highlighting the significance of surface charge and elemental composition. The results demonstrate the substantial impact of both reservoir brine and rock formations on asphaltene stability in crude oil. Further research is needed to unravel the complex mechanisms underlying these interactions and their implications in diverse reservoir environments.
- South America (0.67)
- North America > United States > Texas (0.28)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.70)
- Geology > Mineral (0.95)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.47)
- Geology > Rock Type > Sedimentary Rock (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.48)
- South America > Venezuela (0.89)
- South America > Colombia (0.89)
- North America > United States (0.89)
- (2 more...)