Expro (United States)

Design of overhead power line structures (OPS) for extreme wind has historically been based on traditional strong wind events such as those resulting from the passage of large-scale pressure systems. This does not explicitly account for wind resulting from convective events such as thunderstorm gust fronts, downbursts, derechos, and several other classifications of convective phenomena. This paper discusses design recommendations for these types of wind events, grouped under the term convective straight-line (CSL) winds, which are currently not directly considered in ASCE Manual of Practice No. 74 (MOP 74). This paper does not include discussion of tornados. A new approach aimed at providing improved design recommendations for CSL winds is presented, in which the CSL wind speed is indexed to a mean recurrence interval (MRI) and the differing characteristics of the wind flow are recognized. The wind pressures resulting from the new approach are compared to those calculated using the current version of ASCE MOP 74. Examples of recent observed damage due to CSL wind events are presented which support the importance and relevance of the new approach in design considerations.

Abstract The Remote Clamp Installation System (RCIS), Sheaveless Control Line Manipulator Arm (SCLMA) and Hands Free Hole Cover is an advanced, integrated system that remotely positions control line packages and installs the control line clamp with minimal operator interaction during smart completions. The system is designed to reduce hazards through automated sequencing that eliminates manual operations, hazardous setups, and the need for personnel to enter the red zone. The Hands-Free Control Line Clamp System can install a control line clamp with no personnel entering the red zone. All functions are operated automatically with a one-touch system of controls and sensors, or it can be manually operated utilizing a remote console. Installed sensors ensure seamless operation of the system and guard against damage of equipment and control lines. Typical red zone manual functions are eliminated, replaced by the Integrated System with increased safety and efficiency through automation and delivers repeatability on every clamp installation. The control lines run through the SCLMA as opposed to an overhead sheave and are presented correctly to the tubing to ensure the control line clamp can be installed without damaging the control lines. The retainer lids that secure the control lines are installed in the RCIS out of the red zone. Once the SCLMA has positioned the control lines correctly on the tubing, the RCIS is safe to function, the manipulator slews the clamp head in line with the tubing and translates the clamp head to well center. Once in proper position, the clamp head translates the retainer lid to its position and after acknowledgment from sensors, the clamp head will complete the installation by clamping the male and female collars to retain the retention lid and ensure the control lines are secure. This solution not only enhances the industry's experience with improved safety and reliability, but it is also a paradigm shift that revolutionizes the control line installation process providing a fully autonomous, hands-free solution. This paper will deliver comprehensive details on the novelty of this technology and the solution offered to the industry.

Natural gas is a critical part of the world’s energy supply and plays an important role in the transition to lower-carbon energy sources. The industry’s ability to process natural gas safely and efficiently will continue to rely on an accurate understanding of feed gas composition and contaminants, particularly in enabling future developments via existing infrastructure. Mercury is toxic to organisms, highly volatile and produced from hydrocarbon basins globally. Trace mercury concentrations in the hydrocarbon stream can potentially introduce liquid metal embrittlement hazards to industrial equipment, including cryogenic heat exchangers used to refrigerate liquefied natural gas. Inaccurate measurement of mercury levels can lead to adverse impacts measurable across the areas of health, process safety, environment, operations, waste disposal and decommissioning. Worldwide, significant project cost overruns and processing incidents have resulted from the uncertainty of mercury concentrations in hydrocarbon streams. Successful mercury management ideally begins early in a project’s lifecycle with development decisions informed by accurate measurement of mercury concentrations from reservoirs. Historically, this has been problematic, as mercury contamination and scavenging often result in a large range of uncertainty. The results from a multi-company collaborative study to reduce mercury uncertainty with new downhole sampling techniques will be shared in a case study, including production insights from the Julimar Field, west coast of Australia. The recommendations, procedures and operational best practices discussed will be applicable across the industry and beneficial to any party considering the impact of mercury in the development and processing of natural gas resources.

Abstract The perforation strategy of Dynamic Underbalance (DUB) created the surging effect to remove debris from the perforation tunnels, thus reducing skin for optimal injectivity in this offshore development water injector well in Malay Basin, Offshore Sarawak. The objective was to inject up to 18,000 bwpd for pressure maintenance purposes. In the design phase, perforation software was used to perform the simulation iterations by sensitizing on the number of empty tubing conveyed perforation (TCP) gun chambers added at the top and bottom of perforation intervals. However, due to small gun size (4-½ in.), limited rat hole length and high static underbalance (1,000 psig), the desired amount of DUB using conventional empty gun volume only was not possible to be achieved. As a result, an innovative approach using two Pressure Operated Tester Valves (POTV's) was proposed, to create additional empty space inside the tubular between the POTVs above the packer. However, this created additional challenges which had to be overcome. Presence of empty tubulars in between the POTVs prevented the required hydraulic pressure transmission through the tubulars to activate the perforation guns via normal hydraulic TCP firing head. Therefore, a specialized firing system was required, which consisted of an acoustic communication system triggering downhole electronics to actuate a standard TCP firing head (Top-Fire Dual) - a first for this type of firing head. The POTV was activated by applying a pre-set annular pressure. Opening lower POTV, after the perforation fired, will create the required DUB surge, around 1,000 psi, which help cleaning up the perforation tunnels. Downhole fast gauges (recording in microseconds range) were run as part of the assembly to measure and to confirm the created DUB effect. Both fast gauges as well as acoustic gauges confirmed that 300 psi DUB was created upon gun firing and around 1,000 psi surging was achieved after the two POTVs were opened. Maximum losses recorded at 525 gallons per minute were observed following perforation. The well's injectivity performance was evaluated by performing step rate test and the result confirmed the well was able to meet higher injection rate than the plan.

territorial, bem como o acirramento na disputa de concepções de desenvolvimento territorial entre o capital transnacional e os diferentes povos do campo, sejam povos originários, camponeses,

Abstract Umm Gudair (UG) field is one of the major oil fields of West Kuwait asset. Wells are tested periodically using multiple conventional test separators and data is subsequently used to update Well Performance "Nodal analysis" and "Live Flow Line Surface Network Model". A different approach was tested in 2018 for a mature oil field in the Middle East to evaluate the effectiveness of Clamp-On based SONAR Flow Surveillance solution against existing conventional portable test separator. The objective was to check the performance of the SONAR Flow Surveillance on black oil wells at different flowing conditions, and ultimately implement a new approach to increase the testing frequency, reduce any potential of hydrocarbon release, avoid well shutdown, optimize operating costs, and production optimization. The SONAR Surveillance approach is based on SONAR clamp-on flow meters deployed in conjunction with compositional (PVT) and multiphase flow models for oil and gas wells to interpret the measurements of the SONAR flow meters at line conditions (pressure, temperature, fluid stream composition), and output the gas, oil and water phase flow rates at both actual and standard conditions. The SONAR meter measures the bulk flow velocity (at line conditions), then a flow computer determines the individual phase volume fractions at actual conditions using a PVT model and water-cut. This provides a measure of the oil rate at actual conditions. A shrinkage factor calculated by the black oil model is applied to report oil rate at standard conditions. Gas and water are also inferred in a similar manner. The gas, oil and water flow rates thus determined at actual conditions are further processed and converted to standard conditions as well. The field tests showed that the SONAR Flow Surveillance approach allowed more flexibility in terms of field installation and the measurements are made at actual production conditions unlike other devices that may introduce additional flow restrictions. The SONAR meters diagnostics also provided a more realistic representation of the well flow profile since the measurements are instantaneous versus the "averaging" effects observed when using gravity-based separators. This allows better production surveillance and understanding of changes in well behavior.

Abstract This paper will discuss the design, qualification, testing and planning of a new intervention conveyance technology used to successfully remediate a failed down hole safety valve (DHSV). The technology is a high pressure, reinforced, ¾ inch OD hose that is run on standard wireline equipment thereby reducing footprint, manning, cost and job time compared to other intervention methods. The hose has a working pressure of 12,500 psi with a tensile strength of 14,300 lbs. The system is gravity-fed into the well similar to a conventional wireline system and is spooled onto a wireline add-on drum with conventional wireline pressure control equipment (PCE). The difference compared to a standard wireline equipment is a modified add-on drum which includes a swivel for pumping, a purpose built stripper installed above the lubricator, and special inserts for the BOP. Before mobilisation a series of tests were carried out to qualify the reinforced high pressure hose to ensure it was safe for interventions. Based on successful test results, the coil hose was mobilised and a total of 5 runs were carried out on the first job. These runs included jetting, spotting of chemicals and a caliper survey. The intervention successfully jetted 15% hydrochloric acid (HCl) over the DHSV, and through to surface. The job was an operational success and the DHSV inflow test, post treatment was successful. The reinforced, high pressure coiled hose is a new conveyance technology that positions itself between wireline and coiled tubing. This technology can access wells on locations where running coiled tubing (CT) operations can be a challenge due to limited crane capacities and/or deck space. While coiled hose is not a replacement for CT due to its limited pumping rates (approx. 50lpm) and gravity feeding, it is suitable for spotting chemicals, N2 lifting and light cleanout operations.

AimsTo characterize ticagrelor exposure‐response relationship for platelet inhibition in patients with stable coronary artery disease (CAD) and a history of myocardial infarction (MI), using nonlinear mixed effects modelling and simulation.MethodsPlatelet function data were integrated with plasma concentration data of ticagrelor and its active metabolite AR‐C1249010XX in a population pharmacokinetic (PK) and pharmacodynamic (PD) model, based on two clinical studies. In the ONSET/OFFSET study, PK and platelet function were assessed in 123 CAD patients receiving placebo, ticagrelor (180 mg followed by 90 mg twice daily) or clopidogrel (600 mg followed by 75 mg once daily). In the PEGASUS‐TIMI 54 platelet function substudy, PK and platelet function were assessed during maintenance dosing in 180 prior MI patients receiving placebo, ticagrelor 60 mg or ticagrelor 90 mg twice daily.ResultsPlatelet inhibition by ticagrelor was described by a sigmoidal Emax model. On average, half maximal inhibition was reached at ticagrelor concentrations of 116 (RSE: 5.3%) nmol l–1. Simulations showed that near maximal platelet inhibition is achieved with both ticagrelor 60 and 90 mg twice daily. At simulated lower doses, platelet inhibition is overall reduced, more variable between patients, and show greater peak‐to‐trough variability. Ticagrelor antiplatelet response was similar between the studied patient populations.ConclusionsIn patients with stable CAD or a history of MI, near maximal platelet inhibition is achieved with both ticagrelor 60 and 90 mg twice daily. At modelled doses <60 mg, the response is reduced overall, more variable between patients, and patients will display greater peak‐to‐trough variability.

Abstract Located in the Bjarmeland Platform area of the Barents Sea, Norvarg was discovered by Total in 2011 via wildcat well 7225/3-1, with gas being confirmed in both Jurassic and Triassic formations. A drill stem test (DST) was performed in the Triassic Upper Kobbe formation, but with non-commercial well productivity resulting. The post-DST vision for Norvarg was for stacked heterolithic tidal bar sands connected by large channel sands having better reservoir properties than tested in the first discovery well. The objectives of the follow-on Norvarg-2 appraisal well, drilled in 2013, included verifying the presence of the channel sands defined from seismic, quantifying the channel productivity and demonstrating the contribution of other Kobbe facies by performing an extended duration pressure buildup (PBU). It was a requirement that the selected PBU monitoring method would allow the well to be permanently abandoned in accordance with Norwegian legislation without any requirement for further well intervention. This was achieved by using an emergent new electromagnetic (EM) wireless reservoir monitoring technology, which allowed the pressure buildup to continue undisturbed beyond the end of the DST and final well abandonment. EM wireless monitoring technology is already well established as a means to monitor the reservoir pressure and temperature in abandoned appraisal wells, or suspended development wells, for the purpose of interference testing and reducing uncertainties in connectivity. However, this was the first time that it has been directly applied to monitor a long term PBU beyond final abandonment of a subsea appraisal well. By analysing the pressure transient data the objective was to investigate the presence of any flow barriers in the reservoir that might not be detectable during the course of a typical short duration pressure buildup performed during a DST. This paper presents a case study of the first time application in the Barents Sea of a post-abandonment wireless monitoring solution that successfully delivered high quality reservoir pressure and temperature data for a period of 9 months beyond the end of a DST. Analysis of the data provided clear evidence of internal flow barriers, located 130m and 280m from the wellbore, that were not observed during the normal DST period. This data proved the limited connected volumes and confirmed the requirement for additional development wells, compared with what was known prior to performing the test. This was important information to support the construction of the full field model and the further evaluation of the Norvarg prospect. Due to poor reservoir properties and disappointing deliverability, no viable development concept was identified for Norvarg, even with an increased well count and using fractured vertical and horizontal wells. The license for PL535 was subsequently relinquished in May 2014.