This course discusses the fundamental sand control considerations involved in completing a well and introduces the various sand control techniques commonly used across the industry, including standalone screens, gravel packs, high rate water packs and frac-packs. It requires only a basic understanding of oilfield operations and is intended for drilling, completion and production personnel with some sand control experience who are looking to gain a better understanding of each technique’s advantages, limitations and application window for use in their upcoming completions.
SPE is educating the next generation of aspiring engineers, scientists and managers about the oil and gas industry. This is an opportunity for school students in grades 9–12, studying Mathematics, Physics, Chemistry, Geography or interested in Petroleum Engineering are invited to join SPE members from all over the globe to discover the world of Petroleum Engineering. School teachers are invited to bring a group of 10–15 students. Students will be treated to a range of hands-on activities and presentations from renowned engineers. The oil price outlook coupled with the response of each oil and gas company to make ends meet has led to severe exploration budget cuts.
PETRONAS FLNG SATU (PFLNG1) is a floating liquefied natural gas facility producing 1.2 million tonnes per annum (mtpa) of LNG, on a facility that is 365m long, and 60m wide, making it among the largest offshore facility ever built. The PFLNG1 project is the first of its kind in the world and is the first deployment of PETRONASâ€™ Floating Liquefied Natural Gas (FLNG) technology, consolidating the traditional offshore to onshore LNG infrastructure into a single facility. This will see a giant floating facility capable of extracting, liquefying and storing LNG at sea, before it is exported to customers around the globe. The FLNG journey has come a long way since 2006, with many technological options explored to monetise and unlock the potential of small and stranded gas fields. Moving an LNG production to an offshore setting poses a demanding set of challenges â€“ as every element of a conventional LNG facility needs to fit into an area roughly one quarter the size in the open seas whilst maintaining safety and increased flexibility to LNG production and delivery. The keynote address describes the breakthrough features of PFLNG1 â€“ the worldâ€™s first floating LNG facility; and the pioneering innovation that it brings to the LNG industry.
Cold heavy oil production with sand (CHOPS) involves the deliberate initiation of sand influx during the completion procedure, maintenance of sand influx during the productive life of the well, and implementation of methods to separate the sand from the oil for disposal. No sand exclusion devices (screens, liners, gravel packs, etc.) are used. The sand is produced along with oil, water, and gas and separated from the oil before upgrading to a synthetic crude. To date, deliberate massive sand influx has been used only in unconsolidated sandstone (UCSS) reservoirs (φ 30%) containing viscous oil (μ 500 cp). It has been used almost exclusively in the Canadian heavy-oil belt and in shallow ( 800 m), low-production-rate wells (up to 100 to 125 m3/d).
The claim that the world is irresponsible in rapidly consuming irreplaceable resources ignores technical progress, market pressures, and the historical record. For example, the "Club of Rome," with the use of exponential growth assumptions and extrapolations under static technology, predicted serious commodity shortages before 2000, including massive oil shortages and famine. First, the new production technologies are proof that science and knowledge continue to advance and that further advances are anticipated. Second, oil prices will not skyrocket because technologies such as manufacturing synthetic oil from coal are waiting in the wings. Third, the new technologies have been forced to become efficient and profitable, even with unfavorable refining penalties. Fourth, exploration costs for new conventional oil production capacity will continue to rise in all mature basins, whereas technologies such as CHOPS can lower production costs in such basins. Fifth, technological feedback from heavy-oil production is improving conventional oil recovery. Finally, the heavy-oil resource in UCSS is vast. Although it is obvious that the amount of conventional (light) oil is limited, the impact of this limitation, while relevant in the short term (2000 to 2030), is likely to be inconsequential to the energy industry in the long term (50 to 200 years). The first discoveries in the Canadian heavy-oil belt were made in the Lloydminster area in the late 1920s. Typically, 10- to 12-mm diameter perforations were used, and pump jacks were limited by slow rod-fall velocity in the viscous oil to a maximum of 8 to 10 m3/d of production, usually less. Operators had to cope with small amounts of sand, approximately 1% in more viscous oils. Small local operators learned empirically that wells that continued to produce sand tended to be better producers, and efforts to exclude sand with screens usually led to total loss of production. Operators spread the waste sand on local gravel roads and, in some areas, the roadbeds are now up to 1.5 m higher because of repeated sand spreading. The sharp oil price increases in the 1970s and 1980s led to great interest in heavy-oil-belt resources (approximately 10 109m3). Many international companies arrived and introduced the latest screen and gravel-pack technology but, in all cases, greatly impaired productivity or total failure to bring the well on production was the result. To this day, there are hundreds of inactive wells with expensive screens and gravel packs. The advent of progressing cavity (PC) pumps in the 1980s changed the nonthermal heavy-oil industry in Canada. The first PC pumps had low lifespans and were not particularly cost-effective, but better quality control and continued advances led to longer life and fewer problems. The rate limits of beam pumps were no longer a barrier and, between 1990 and 1995, operators changed their view of well management.
Achieving zero harm has been the talk of the industrial sector to reduce harm to as low as possible. The management of health, safety, security and environment (HSSE) should not be stagnant. It is time to rethink and reassess how the industry can prepare, mitigate and respond to stay ahead of emerging technical, regulatory and societal challenges. This session will engage leaders to discuss opportunities and challenges, share experiences and lessons learnt, and on how technology and digitalisation may affect the quality and productivity of the work sites - all of which are critical in shaping the future of HSSE in the region. The current presentation date and time shown is a TENTATIVE schedule.
This year, as part of the Opening Ceremony, SPE brings you two panel sessions that will focus on the conference theme “Co-operating Towards a More Competitive Environment to Encourage Investment Projects.” The panels will represent two different perspectives—the investors and operators in the region. Digitalisation is emerging as a technological driver of change around the world and is transforming how companies in the oil and gas industry operate. A wave of digital technologies and initiatives are leading this new era of innovation and opportunity. Investments in programmes such as analytics, data science, artificial intelligence, cloud computing, and other emerging technologies are being pursued to improve safety, reliability, and efficiency with the expectation of delivering significant value through improved processes and systems.
A challenge in oil-reservoir studies is evaluating the ability of geomechanical, statistical, and geophysical methods to predict discrete geological features. This problem arises frequently with fracture corridors, which are discrete, tabular subvertical fracture clusters. Fracture corridors can be inferred from well data such as horizontal-borehole-image logs. Unfortunately, well data, and especially borehole image logs, are sparse, and predictive methods are needed to fill in the gap between wells. One way to evaluate such methods is to compare predicted and inferred fracture corridors statistically, using chi-squared and contingency tables.
In this article, we propose a modified contingency table to validate fracture-corridor-prediction techniques. We introduce two important modifications to capture special aspects of fracture corridors. The first modification is the incorporation of exclusion zones where no fracture corridors can exist, and the second modification is taking into consideration the fuzzy nature of fracture-corridor indicators from wells such as circulation losses. An indicator is fuzzy when it has more than one possible interpretation. The reliability of an indicator is the probability that it correctly suggests a fracture corridor. The indicators with reliability of unity are hard indicators, and “soft” and “fuzzy” indicators are those with reliability that is less than unity.
A structural grid is overlaid on the reservoir top in an oil field. Each cell of the grid is examined for the presence and reliability of inferred fracture corridors and exclusion zones and the confidence level of predicted fracture corridors. The results are summarized in a contingency table and are used to calculate chi-squared and conditional probability of having an actual fracture corridor given a predicted fracture corridor.
Three actual case studies are included to demonstrate how single or joint predictive methods can be statistically evaluated and how conditional probabilities are calculated using the modified contingency tables. The first example tests seismic faults as indicators of fracture corridors. The other examples test fracture corridors predicted by a simple geomechanical method.