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.
Oil production from shale and tight formations will increase to more than 6 million barrels per day (b/d) in the coming decade, making up most of total U.S. oil production (> 50%). However, achieving an accurate formation evaluation of shale faces many complex challenges. One of the complexities is the accurate estimation of shale properties from well logs, which is initially designed for conventional reservoirs. When we use the well logs to obtain shale properties, they often cause some deviations. Therefore, in this work, we combine cores and well logs together to provide a more accurate guideline for estimation of total organic carbon, which is primarily of interest to petroleum geochemists and geologists.
Our work is based on Archie's equation. Resistivity log will lead to some incorrect results, such as total resistivity, when we follow the conventional interpretation procedure in well logs. Porosity is another complex parameter, which cannot be determined only by well log, i.e. density, NMR, and Neutron log. Therefore, the flowchart of TOC calculation includes five main parts: (I) the shale content calculation using Gamma log; (II) the determination of shale distributions using Density and Neutron logs and cross-plot; (III) the calculation of total resistivity at different distribution types; (IV) obtaining porosity using core analysis, NMR and density logs; and (V) the calculation of TOC from modified Archie's equation.
The results indicate that the shale content has a strong effect on estimation of water saturation and hydrocarbon saturation. Especially, the effect of shale content is exacerbated at a low water saturation. A more accurate flowchart for TOC calculation is established. Based on Archie's equation, we modify total resistivity and porosity by combining Gamma Log, Density Log, Neutron Log, NMR Log, and Cross-plot. An easier way to estimate porosity is provided. We combine the matrix density and kerogen density together and obtain them from core analysis. Poupon's et al. (1954) laminar model has some limitations when applying in shale reservoirs, especially at a low porosity.
Literature surveys show few studies on the flowchart of TOC calculation in shale reservoirs. This paper provides some insights into challenges of well logs, core analysis in shale reservoirs and a more accurate guideline of TOC calculation in shale reservoirs.
The traditional advantage of petroleum-based transport fuels of unmatched energy-density and affordability is diluted with the requirement to lower atmospheric carbon. However, despite a significant R&D effort and investment over the last three decades, humanity is still looking for carbon neutral alternatives to petroleum that can be commercially viable. This paper presents meaningful novel approaches to deal with carbon abatement utilizing petroleum that have a better chance to succeed in fulfilling the underlying techno-economic desirables.
While the multi-directional work performed in the past on the subject has informed us on a variety of related topics, going forward the society can benefit from a systematic approach to solving atmospheric CO2 problem building on the petroleum advantage. A framework formulating the challenge in terms of techno-economic and environmental requirements is presented that narrows down further work to only meaningful and promising leads. With this framework in mind a few specific pathways are proposed that naturally hold the desired traits if certain conditions are met. These conditions in turn define specific objectives of the subsequent developmental work. While it is premature to suggest any of these will develop into a commercially viable pragmatic method, due to the underlying criteria they hold a better chance to be successful. The presented pathways using advances in electro-chemistry, nanoscience, rational design, and other areas range from (a) mimicking natural fixation of CO2 as in plants to produce tailored polysaccharides or food, to (b) converting CO2 to substances such as carboxylic acids for easy and cost effective sequestration, to (c) changing the way petroleum fuel is used in internal combustion engines to alter the exit state of oxidation of carbon so that the waste product is easily and economically captured compared to the conventional waste product - CO2.
One outcome from the framework results in collapse of the economic models and associated technical approaches that aim to convert CO2 to sellable products, owing mainly to the volume of the global GHG challenge. On the other hand, a common element in the proposed promising leads is to deal with the problem of carbon abatement as an added step with an associated cost. The lower this cost, the less diluted the petroleum-advantage. In this context the framework also points to a range of relative costs that the carbon abatement approaches have to work within to retain the petroleum advantage.
The outlined technical approaches of carbon abatement are not previously discussed in the literature and hold the promise to help combat the global GHG challenge in a more practical and significant way.
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.
Wax and paraffin precipitation is a major problem around the world, costing the petroleum industry billions of dollars yearly. As temperature drops below the Wax Appearance or Wax Precipitation Temperature (WAT/WPT) of crudes, paraffin starts to precipitate out and restrict or block the effective flow. There are different methods, such as mechanical and chemical remediation to deal with wax issues. Among the latter ones, the use of surfactants is favorably looked upon since they are small molecules with surface activity properties. This study aims to introduce novel aliphatic non-ionic surfactants with different chain length and degree of ethoxylation. In addition to chain length, the impact of branching on the hydrophobic part of the surfactants was also studied.
A waxy crude oil from Brazil was characterized through determining its carbon distribution, WAT, viscosity and density based on industry standard methods. Several surfactants with different combinations of chain length/ethoxylation number were then selected for screening. The performance of surfactants was evaluated based on data obtained from treated crude versus the control sample through different experiments. Rheology studies were conducted at 50 to -10°C and at shear rates of 5 and 300 s-1. The cold finger instrument was utilized to determine paraffin content of the untreated and treated crude. Finally, the paraffin crystal size was analyzed through microscopic studies.
The results showed that shear rate can affect the wax treatment outcome as well as the effective concentration of surfactant. Therefore, it is important to assess the rheology at high and low shear rates. Some surfactants in the present study performed great at both low and high shear rates and were able to reduce the viscosity by 80% at temperatures well below WAT of the crude oil. The microscopy results confirmed that wax crystals were reduced in size and were more dispersed after treating the crude with these surfactants. The findings from High Temperature Gas Chromatography showed that the deposition of heavy fraction part of crude (C40+) is reduced after treating the crude oil with the surfactants in the present study.
The current study addresses the wax precipitation/deposition challenges of heavy crudes and proposes mitigating them through the use of some new non-aromatic non-ionic surfactants. The chemistries and findings of this research help the oil and gas industry to save money and time by mitigating flow assurance problems.
Md Jalil, Abdullah Al Mubarak (PETRONAS Research Sdn Bhd) | Mat Isa, M Faudzi (PETRONAS Research Sdn Bhd) | Rostani, Khairul (PETRONAS Research Sdn Bhd) | Othman, Nurzatil Aqmar (PETRONAS Research Sdn Bhd) | M Shariff, Azmi (Universiti Teknologi PETRONAS) | Lau, Kok Keong (Universiti Teknologi PETRONAS) | Partoon, Behzad (Universiti Teknologi PETRONAS) | Tay, Wee Horng (Universiti Teknologi PETRONAS)
As easy gas resources around the world are depleting; high Carbon Dioxide (CO2) gas fields are thrust into the spotlight to become new candidates for field development. However, the presence of oftentimes sizable Carbon Dioxide contents in the gas reservoir (can be up to 80% volumetric) introduced a huge technical and economic challenges towards the field exploitation.
Over the last few years, several studies have been conducted on cryogenic technologies such as cryogenic distillation and supersonic nozzle in CO2 separation for fields containing more than 40% of CO2. Based on the studies, these new cryogenic technologies have shown to have high potential in separating CO2 from natural gas offshore to be utilized under carbon, capture, storage and utilization (CCUS) project.
The new cryogenic technologies are currently being tested for the proof of concept. Hence, a pilot plant, which is a scaled down version of the technology was developed. One of the major challenges faced during the pilot plant testing is the emergency depressurization philosophy as the process involves CO2 solids handling which is uncommon to the industry standard. Depressurization of high CO2 fluid at cryogenic temperature would lead to possibility of CO2 solids formation, hence potential blockage of process equipment and venting line.
Therefore, this paper will focus on the design of the pressure relieving system of such a facilities. It would also touched on the implementation of the pressure relieving system during the operation of the pilot tests and as well as the tests designed specially to test the pressure relieving system. Finally the paper would give a few proposals on improvements to be made to such system. It is also the ultimate aim of the authors and the team to introduce a new philosophy for Cryogenic CO2 Blowdown system to the process industry.
Gardiner Hill, Group Environment Technology Manager with BP, spoke at the second event that the Aberdeen Emerging Leaders Program has organized with the SPE Aberdeen Section. Hill is also Chairman of the CO2 Capture Project, a Vice Chair of the European Union Technology Platform for Zero Emissions Fossil Fuel Power Plants, and Chairman of the Industry Assn. Attendance at the event was 130. Hill said that most scientists now acknowledge a direct link between the dramatic increase in CO2 concentrations in the atmosphere and the rise in global temperature. The Earth can absorb CO2 only at a limited rate, and to stabilize at the required atmospheric concentration of 550 ppm, emissions would have to drop to half their current value. And energy demand will double in the next 50 years.
Researchers at the University of Massachusetts, Amherst, performed a life-cycle assessment for training several common large AI models. They found that the process can emit more than 626,000 lbm of carbon dioxide equivalent—nearly five times the lifetime emissions of the average American car. Southwest Research Institute is working to improve the accuracy of pipeline leak detection using sensors, artificial intelligence, and deep learning.
Innovation is critical to the future success of the oil and gas industry (
As a way of addressing this, the TechX programme at the Oil & Gas Technology Centre has launched TechX Ventures in July 2018 – a partnership with Deep Science Ventures (DSV) – that combines deep science with engineering to create the next generation of start-up companies with technologies that will position the oil and gas industry for a sustainable future in a low carbon economy.
The start of the programme was a workshop held with industry, academia and the scientific community, to identify areas where new thinking and technology could open up significant opportunities. Three challenge themes were developed, each of which became an opportunity areas for DSV to address. These are:
As part of the TechX Ventures programme, DSV recruited thirty scientists and engineering experts from across the world to tackle the opportunity areas and at the end of the nine-month programme a total of six new start-up companies with new intellectual property were created and invested in by DSV. Of these six, two were selected to join the coveted TechX Pioneer accelerator programme run by OGTC in Aberdeen. These companies are called Eltera and Optic Earth.
Recovery and valorization of wasted gas associated to methane processing (i.e. leakages from rotating equipment and flared gas) has usually been avoided due to the inherently limited amount of gas of these streams. Moreover, the technical complexities are further enhanced when applied to aging infrastructures and old compression unit designs, making the solution complex and less cost-effective.
However, emission control regulation is progressively limiting the atmospheric release of gases from the hydrocarbon production and processing. These requirements have triggered the development of new technical solutions to limit even small gas streams typically neglected in the past. Typical examples of small leakages tolerated in gas processing are associated with the Dry Gas Seals (DGS) primary vents. The limited amount of gas released did not justify a recovery system, leaving flaring as the only viable option.
In this paper, the technical solutions for compressor DGS primary vent recovery are presented, with further discussion on the integration into the gas process. Financial sustainability of the solutions is also presented, with the analysis of two selected cases. The presented solutions are designed to reflect the positive impact of wasted gas reduction, contributing to reaching environmental sustainability targets in oil and gas.