Liang, Jiabo (CNOOC Iraq Limited) | Jin, Liping (CNOOC Iraq Limited) | Li, Wenyong (CNOOC Iraq Limited) | Li, Qiang (CNOOC Iraq Limited) | Laaby, Hussein Kadhim (Missan Oil Company) | Ammar, Ali Jabbar (Missan Oil Company) | Tayih, Ali Ouda (Missan Oil Company) | Muteer, Raad Fahad (Missan Oil Company) | Saadawi, Hisham N H (Baker Hughes, a GE company) | Harper, Christopher (Baker Hughes, a GE company) | Tuck, Jon O. (Baker Hughes, a GE company) | Fang, Yongjun (Baker Hughes, a GE company)
CNOOC Iraq Limited operates three oil fields in Missan Province in Iraq. They are all large onshore oilfields located 350 kilometers southeast of Baghdad. In order to support reservoir pressure, plans are underway to implement a water injection scheme. The injection water comes from three different sources; produced water, aquifer water as well as river / agricultural water. Considering the nature and varying chemistry of the source water, particular attention had to be given to selecting the material for the water injection wells. This paper describes the approach adopted in selecting the materials for Missan fields' water injection system.
Trelleborg's offshore operation has consolidated its range of high-performance thermal insulation materials and will house them under one brand, Vikotherm. The company said all products in the Vikotherm range guarantee maintained flow rates, optimum productivity, reduced costs, and protection against wax and hydrate formations. One of the featured products in this range is R2, a three-layer coating system that protects against corrosion, hydrogen-induced stress cracking, wax and hydrate formation, and mechanical loads. Using a newly designed mobile production unit, the material can be installed on site and can operate in temperatures ranging from -56 F to 311 F and water depths as low as 9,843 ft. Another material, the S1, is based on nonsyntactic silicone technology and is applicable to risers and flowlines, subsea trees, pipeline end manifolds, and pipeline end terminations.
T.D. Williamson's SmartPlug isolates pressure in specific sections of pipelines and risers so that repairs or interventions can be carried out safely. Operated by remote control, the tool is certified "safety class high" in accordance with OS-F101 for submarine pipeline systems, the company said. It is certified and type approved by Det Norske Veritas to execute independent double-block isolation to provide a safe environment for divers while working near a pressurized gas pipeline.
Today, almost half of Western Canada's natural-gas production comes from the Triassic-aged Montney formation, a sixfold increase over the last 10 years while gas production from most other plays has declined. In the last few years, demand for condensate as diluent for shipping bitumen has driven development of liquids-rich Montney natural gas leading to a surge in gas production and gas-on-gas competition in the Western Canadian Sedimentary Basin (WCSB), which has driven local natural gas prices down. This has had a material effect on the operations and finances of companies active in the Western Canada and is reshaping the Canadian gas industry. A significant portion of this growth has taken place in NE British Columbia and with the planned electrification of the industry in British Columbia, including the nascent LNG operations, will influence tomorrow's power industry in this region. NE British Columbia is a geographically large area with sparse population and the power supply into this region has lagged behind development of oil and natural gas resources. The area was originally served from geographically closer NW Alberta. More recently, supply was established from the BC Hydro power grid with the most significant developments being Dawson Creek-Chetwynd Area Transmission (DCAT) completed in 2016 and the additional 230 kV transmission projects scheduled for completion in 2021.
Results of the Integrated CCS for Kansas pre-feasibility study indicate that large-scale CO2 capture, transportation and storage in saline aquifers in Kansas is both technically and economically feasible and deserving of further study. Based on the technical work on multiple geologic sites, there appear to be up to four sites within the North Hugoton Storage Complex (NHSC) in Southwest Kansas where >50 million tons CO2 could be injected over a 25- to 30-year period and safely stored in a set of stacked saline aquifers at ideal depths of 5200-6400 ft. The saline aquifers (Mississippian Osage, Ordovician Viola, and Cambrian-Ordovician) are overlain by oil reservoirs that are candidates for CO2 Enhanced Oil recovery (EOR). Of the four possible sites in the NHSC, the Patterson site was chosen as the primary site for a CarbonSAFE Phase II project. Patterson was chosen because the operator of the overlying fields, Berexco, was a long-term research partner of the Kansas Geological Survey (KGS), having participated in several DOE-funded studies with the KGS. Patterson has EOR opportunities in overlying reservoirs and most of the prospective injection site is already unitized.
Capture, compression and transportation of large volumes of CO2 is economic in the region, particularly since the extension and expansion of Federal 45Q tax credits in February 2018 that provide $35/ton for CO2 stored during EOR and $50/ton if stored in a saline reservoir and can be captured for a 12-year period. Without these credits, saline aquifer storage is not economically viable. The most economic scenario involves CO2 aggregated from multiple ethanol plants via small-diameter pipelines that tie into a main trunk line for delivery to market. CO2 EOR likely needs to be part of the system to provide economy of scale and, potentially, additional subsidy for saline aquifer injection through CO2 sales. High capture costs at the two power plants and refinery in this study make them non-economic options without further subsidy that may arise from a large regional pipeline system.
Legal, regulatory, public policy aspects of a project of the scale envisioned will require significant changes at the State level. In particular, legislation that would regulate capture, transportation, injection and storage as a public utility would be required along with allowances for eminent domain to be used for pipeline right-of-way and pooling of pore space. Streamlining the U.S. EPA UIC Class VI well permit process and/or establishing State primacy would further support development of commercial-scale CCS. Effective public outreach is critical for support of State regulatory changes, and for public acceptance, particularly in light of possibility for induced seismicity due to injection in certain areas and mixed public opinions about pipeline construction.
Wang, Ningyu (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX 78712, USA) | Prodanovic, Maša (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX 78712, USA) | Daigle, Hugh (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX 78712, USA)
Precipitation and deposition of paraffin wax and hydrates is a major concern for hydrocarbon transport in pipelines, tiebacks, and other production tubing in cold environments. Traditionally, chemical, mechanical, and thermal methods are used to mitigate the deposition at the expense of production interruption, complex maintenance, costs, and environmental hazards.
This paper studies the potential of nanopaint-aided electromagnetic pigging. This process has potentially low production impact, simple maintenance, low energy cost, and no chemical expense or hazards. The electromagnetic pig contains an induction coil that emits an alternating magnetic field. The alternating magnetic field induces heat in the nanopaint coating (i.e. coating with embedded paramagnetic nanoparticles) on the pipeline's inner wall and in the pipeline wall itself. The heat then melts and peels off the wax and hydrates adhering to the pipeline, allowing the hydrocarbon to carry them away.
We analyze the heating effectiveness and efficiency of electromagnetic pigging. The heating effectiveness is measured by the maximum pigging speed that allows deposit removal. The heating efficiency is measured by the ratio of the heat received by the wax over the total emitted electromagnetic energy, which we define as the pig induction factor.
Based on our numerical model, we compare the pig induction factor for different coil designs, different hydrocarbon flow rates, and different pig traveling speeds. We find that slower pig speed generally improves the pigging performance, that shorter solenoids with larger radius have higher efficiency, and that the oil flow does not considerably affect the process. We re-evaluate the maximum pig speed defined by the static pig model and confirm that a solenoid with larger radius allows higher pig speed.
We investigate the potential of a novel, low-maintenance electromagnetic pigging method that poses minimal interruption to production. This investigation is a basis for a new technology that stems from initial experimental investigation done by our collaborators. We here provide parameters for pig design and pigging protocol optimization, and will put them in practice in our future lab experiments.
Wang, Zhihua (Northeast Petroleum University) | Zhu, Chaoliang (Northeast Petroleum University) | Lou, Yuhua (PetroChina Daqing Oilfield Engineering Company Limited) | Cheng, Qinglin (Northeast Petroleum University) | Liu, Yang (Northeast Petroleum University) | Wang, Xinyu (PetroChina Daqing Oilfield Company Limited)
Wax crystals can aggregate and precipitate when the oil temperature decreases to below the wax appearance temperature (WAT) of waxy crude oil, which has undesirable effects on the transportation of crude oil in pipelines. Thermodynamic models considering the molecular diffusion, shearing dispersion, and shear stripping as well as hydrodynamic models have been developed for predicting the wax deposition in crude oil pipelines. However, the aggregation behavior of wax crystals during crude oil production and transportation is not well understood. The microscopic rheological parameters have not been related to the bulk flow parameters in the shearing field, and the prediction of the wax deposition behavior under complex conditions is restricted by the vector characteristics of the shearing stress and flow rate. A set of microscopic experiments was performed in this study to obtain the basic information from images of wax crystals in shearing fields. A novel method of fractal dimensional analysis was introduced to elucidate the aggregation behavior of wax crystals in different shear flow fields. The fractal methodology for characterizing wax crystal aggregation was then developed, and a blanket algorithm was introduced to compute the fractal dimension of the aggregated wax crystals. The flow characteristics of waxy crude oil in a pipeline were correlated with the shearing stress work, and a wax deposition model focusing on shearing energy analysis was established. The results indicate that a quantitative interpretation of the wax crystal aggregation behavior can be realized using the fractal methodology. The aggregation behavior of the wax crystals is closely related to the temperature and shearing experienced by the waxy crude oil. The aggregation behavior will be intensified with decreasing temperature and shearing effect, and a wider fractal dimension distribution appears at lower temperatures when the same shear rate range is employed. The lower the fractal dimensions obtained at high temperature and strong shear action, the weaker will be the nonlinear characteristics of the wax crystal aggregation structure, and thus, the potential wax deposition will be inhibited during waxy crude oil production and transportation. Furthermore, the improved model provides a method for discussing the effects of the operating conditions on wax deposition. The average relative deviation between the improved model prediction results and experimental results from the literature is 3.01%–5.32%. The fractal methodology developed in this study and the improvement in wax deposition modeling are beneficial for understanding and optimizing flow assurance operations in the pipeline transportation of waxy crude oils, and the results are expected to facilitate a better understanding of the wax crystallization and deposition mechanism.
Experience has shown that hydraulic fracturing operations can introduce and/or stimulate microbial populations in the wellbore that in turn may lead to undesired corrosion, souring or other production issues. Biocides are applied to prevent the establishment of problematic microbes. Characterizing and quantifying which microbes will be introduced to a well using molecular techniques allows for optimized or even proactive treatment and prevention strategies to be implemented, whereas, traditional microbial testing methods have proven insufficient.
Once the standard for microbial assessments in the oil and gas industry, culture media bottles are now just one of many available tests. Tests vary by their resolution (culturable, active and living, total microbes), and the information they yield. Some tests target very specific microbial subgroups of concern (culture media, qPCR), while others evaluate all microbes within the sample (ATP, qPCR, 16S rRNA sequencing). In the case studies presented, water and produced fluids were collected from all pertinent frac sample points (source waters, pre- and post-chem and post completions) and were assessed using the suite of microbial methods stated above.
Three case studies are presented with several noteworthy observations regarding the value microbial tests provide to frac operations. First, culture media-based testing consistently resulted in incoherent and confusing data that failed to correlate with the remaining testing technologies. Second, ATP technology provided efficient and timely testing which lent itself well to on-site, evidence-based decision making. During one of the fracs, ATP results were used to modify and optimize a microbial control program on-the-fly. Third, DNA-based testing (qPCR and 16S rRNA sequencing) provided the most comprehensive insight into the microbial communities exposed to the well, and those that established post-completions.
Overall, holistic microbial testing offers the user key information required to design and implement successful microbial control programs for frac. Without it, microbial issues plagued production efforts. Culture media tests provided limited and unreliable information and were deemed not suitable for frac operations. ATP provided a useful microbial load in real-time but could not elucidate the types of microbes present. DNA testing filled this gap by providing quantities and types of microbes present.
Apart from assessing microbial control programs during the frac, monitoring the production fluids is essential to assuring continued well performance. The acknowledgment of the role microbes play in well completions, and the testing technology to evaluate oilfield microbes is rapidly advancing. Here we present some of the first case studies highlighting the use of molecular, DNA-based technology for assessing hydraulic fracturing operations and showing the fallacy of culture media-based testing which is the current industry standard.
A survey of pipeline industry publications generated a database of over 80 collapse tests of cold-expanded line pipe. The data are compared to casing collapse ratings per
Further investigation revealed that, for two operators, the vast majority of offshore surface casing is line pipe that has been cold-expanded without stress relief. Several risk mitigation alternatives were considered. In the short term, the risk can be managed through learning bulletins, design guidelines and operational procedures. The preferred mitigation is to change the collapse rating for cold-expanded line pipe used as casing. This is a long-term solution involving industry standards and the subsequent adoption through commercial design software.
The work described in this paper has led to a ballot change for the next edition of API TR 5C3. This paper is presented to provide drilling industry awareness of the lower collapse performance of cold-expanded line pipe and to add context for selection of an appropriate alternative rating.
SPE's publication for the Projects, Facilities, and Construction (PFC) technical discipline, Oil and Gas Facilities (OGF), has recently launched a monthly section which will feature synopses of editor-picked SPE technical papers on PFC topics. OGF Selection Editor Gerald Verbeek will pick three papers each month that are then synopsized by SPE editorial staff and published on the OGF website. Verbeek was previously the executive editor for peer-reviewed papers in OGF and was recognized as "A Peer Apart" honoree for peer-review of more than 100 technical papers. He has picked Corrosion and Scaling for the first selection, a topic that affects all involved in oil and gas facilities. "Early in my career I spent about a year as a corrosion engineer to learn the fundamentals, only to discover that without keeping scaling and corrosion in mind, it is impossible to a be a good facilities engineer," said Verbeek in his introductory article about the new section.