One of the primary energy sources, natural gas is widely used for power generation, industrial production, transportation, commercial buildings, and households. The industry is a capital intensive one for all stages from exploration to delivery. Two types of supplies: pipeline and Liquefied Natural Gas (LNG), recently have faced a direct intra-industrial competition. Physical nature of methane and associated transportation costs lead to domination of so-called "natural monopolies" or "national champions" and strict government regulation, which postponed the development of free trade and competition. After decades of technical innovations and cost curve improvement in LNG sector, shale boom in the USA, increasing global consumption, and demand for supply diversification reformulated the role of gas in the global energy balance. While the pipeline sector remains to be in the hands of large corporations and a subject of strategic interstate and international agreements, or LNG provides more diversity and flexibility of trade. However, even after a long history of LNG shipment since the late 1950s, LNG market is still regional with high spreads between countries and terms of delivery.
The paper presents the evolution of business models in the natural gas industry, focusing on the primary drivers as government regulation, production technologies, and regional markets trends on the way to liberalization and cointegration. Thus, our primary objective is to show relative influence power of these drivers. This analysis also defines the competitiveness of corporate business model under conditions of asymmetric information, regional gas markets, deregulation trends, fast-growing production technologies and downstream infrastructure (specifically in LNG sector). We also enclose the analysis of the most globally competitive gas projects. We analyze changes in value chain change and trading contracts. Our methodological approach poses model-based principles, including option and contract models, jointly with game theory elements.
Panja, Palash (Department of Chemical Engineering, and Energy & Geoscience Institute, University of Utah) | Velasco, Raul (Energy & Geoscience Institute, University of Utah) | Deo, Milind (Department of Chemical Engineering, University of Utah)
In this work, we estimate the Stimulated Original Oil In Place (SOOIP) of hydraulically fractured horizontal wells in prominent shale plays. This is done by compiling production data from hundreds of wells belonging to the Bakken, Niobrara, Wolfcamp, Eagle Ford, Bone Springs, and Woodford totaling over 2,500 wells. Additionally, we present probabilistic distributions of SOOIP with mean, standard deviation, P10, P50, and P90 estimates for each play.
To circumvent the challenge of data availability for each well, we use the findings of a previous study where all reservoir unknowns are grouped into two major parameters. One of these parameters, alpha, is a function of the stimulated reservoir volume, compressibility, and pressure drawdown, where the last two are unknowns. While alpha is determined with high confidence for each well, we account for the uncertainty of compressibility and drawdown values across wells by assuming a normal distribution for these parameters. Lastly, by incorporating 1 million Monte Carlo samplings and a Mersenne Twister random number generator we estimate SOOIP distributions for each play with varying degrees of confidence.
The final results show that the Niobrara and Bakken have the highest mean SOOIP values per well while the values for the Woodford and Bone Springs are the lowest among all six plays considered. Volumetric calculations using data from the literature qualitatively corroborate these findings. New insight on the stimulated volumes per well for prominent shale plays can be derived from these results as they correlate to horizontal well length, formation thickness, and hydraulic fracture half-lengths in each play.
Horizontal shale wells’ drilling has been challenging the technical limits since its beginning, and the same challenge was faced in completion phase with the Plug&Perf method. Vaca Muerta shale play in Argentina is not an exception of this. Lateral lengths in Vaca Muerta achieved 800-1000 m in the beginning of its shale operations with horizontal wells, and now they are designed to achieve more than 2500 m, even 3200 m, similar to the major laterals in the main shale plays of USA and Canada.
In Plug&Perf completion method, new materials for fracture plugs and advanced designs of perforating guns were also influenced by the technological advances of the industry.
Coiled Tubing (CT) was not an exception of this trend. CT strings for milling out plugs have been demanded to achieve longer laterals without loosing efficiency, with the required Weight on Bit (WOB).
Two main aspects must be taken into account for CT string design: Lateral reach with enough WOB depends mainly on geometrical aspects (external diameter and combination of different wall thicknesses) in order to minimize the occurance of buckling by decreasing the friction caused by the contact of the string with casing wall. Extended fatigue life
Lateral reach with enough WOB depends mainly on geometrical aspects (external diameter and combination of different wall thicknesses) in order to minimize the occurance of buckling by decreasing the friction caused by the contact of the string with casing wall.
Extended fatigue life
In this way, a new technology in CT manufacture was developed and patented, and introduced by the first time in the market in 2005 (R. Rolovic. M. Valdez et al, 2017). This technology employs materials with a new chemistry, and involves a heat treatment for achieving a complete microstructure transformation and homogeneous properties all along the string. Hence, bias weld, heat affected zone and longitudinal seam weld.
Field performance of this new technology in CT has gone beyond the experience achieved with conventional CT. Furthermore, testing of several strings after being removed from the field have shown a superior residual fatigue life than conventional strings, confirming the stated conclusions and pevious observations.
Li, Maowen (Sinopec Petroleum Exploration and Production Research Institute) | Ma, Xiaoxiao (Sinopec Petroleum Exploration and Production Research Institute and China University of Petroleum) | Cao, Tingting (Sinopec Petroleum Exploration and Production Research Institute) | Tao, Guoliang (Sinopec Petroleum Exploration and Production Research Institute) | Li, Zhiming (Sinopec Petroleum Exploration and Production Research Institute) | Jiang, Qigui (Sinopec Petroleum Exploration and Production Research Institute) | Wu, Shiqiang (Sinopec Jianghan Oilfield Company)
Changes in past climatic conditions resulted in the formation of various types of source rocks, such as lacustrine evaporites, freshwater mudstones and coal-bearing formations (Liu et al., 1985), all of which are excellent sources of crude oil in China. The lacustrine evaporitic formations in eastern China have been studied for their petroleum generative potential (e.g.
ABSTRACT: The ability of shale formations to deform and seal the annulus around the casing has been documented in publications and industry presentations. Moreover, development of such natural seals (barriers) in the annulus has been utilized in Permanent plug and abandonment (PP&A) operations as an alternative to conventional PP&A methods and materials. It has been reported that this in fact facilitated the PP&A operations and resulted in considerable cost savings. The objective of this paper is to present the work done to assess the potential of the Gearle formation in the Griffin fields in the southern Carnarvon Basin in Western Australia with respect to its ability to provide a barrier during the PP&A operations. For this purpose, we identify first and second order factors controlling the creep deformation of shales/mudstones. In turn, we compared the material and mechanical properties of Gearle formation with the formations forming seal at NCS and also with other measurements completed on other shales globally. In addition, we have utilized simple numerical creep models to assess the creep potential of Gearle formation to form a barrier around the casing. Later during PP&A operations, we acquired IBC-CBL-VDL logs in the wells and observed evidence of bonding. We, finally, present the cement log bond interpretations in the intervals we observed casing-formation bonding.
Permanent plug and abandonment (PP&A), as common industry practice, is performed by setting a number of cement plugs inside the casing strings. In certain cases, annular seal, traditionally provided by annular cement, may not fulfil the abandonment requirements and rather costly remedial cementing, milling or cut and pull of casing has to be performed in order to complete the PP&A of a well. However, certain rock types, i.e., shale and salt, have the potential to satisfy the requirements for PP&A and can therefore be used as well barrier elements as long as they can be proven to have the required strength and seal around the casing over a sufficient interval. In particular, the ability of shale to deform and seal the annulus around casing to form a barrier has been documented with the experience of operators in the Norwegian Continental Shelf (NCS) in the North Sea -providing ease of operations and cost savings (Carlsen, 2012, Williams et. al, 2009).
ABSTRACT: The rapid growth of the North American shale gas industry has been made possible through technology advances in extended-reach horizontal drilling and multistage hydraulic fracture stimulations. However, the injection of large volumes of fluids during hydraulic fracturing have also raised concerns regarding related induced seismicity. Several recent empirical and numerical studies have investigated the effects of operational factors such as injection volume and rate on the magnitude distribution of induced seismicity events; studies on the influence of geological factors are more limited. A key geological factor is the influence of rock mass stiffness. Results are presented here investigating the effects of a stiffness contrast between adjacent formations on the magnitude distribution of induced seismicity events. A representative scenario based on the Montney play is modeled using a series of 3-D distinct-element simulations. Results show that triggered slip displacements across a fault that transects a stiffness contrast boundary are non-uniform, and that the larger slip displacements (and induced seismicity events) occur in the formation with the higher stiffness. This helps to explain observations of induced seismicity below the formation targeted by hydraulic fracturing.
In recent years, certain regions across Canada and the United States have experienced a significant increase in seismicity relative to historical baselines (Keranen et al. 2014; Ellsworth 2013; Farahbod, Kao, Walker, et al. 2015; Farahbod, Kao, Cassidy, et al. 2015). This increase has been linked to hydraulic fracturing and deep wastewater disposal wells associated with the development of new unconventional oil and gas resources (Horton 2012; BC Oil and Gas Commision 2012; BC Oil and Gas Commission 2014). The hydraulic fracturing process involves pumping fluids under high pressure into sections of a wellbore to generate fractures in order to increase the permeability and stimulated volume of the reservoir rock. At the same time, this injection of fluids into deep formations also serves to create localized increases in pore pressures, which in the presence of a critically stressed fault, can act to reduce the effective normal stresses acting on the fault, resulting in slip and induced seismicity. The generation of seismicity has raised public, industry, and regulator concerns in affected regions. For the most part, the events generated have very low magnitudes (< M3). However, there have been incidents of larger earthquakes (>M3) that in cases involving higher population densities and sensitive ground conditions have resulted in damage to infrastructure and property (Tagliabue 2013). To properly assess a targeted formation for induced seismicity hazard potential, it is important to study the factors that influence the triggering of fault slip and range of possible event magnitudes.
This publication presents how the flow assurance strategies of a sandstone oil field were optimised after numerous production upsets. It also uses economics to justify facilities enhancement projects for flow assurance. Field F is an offshore oil field with 210 feet water depth and eight subsea wells tied back to a third party FPSO vessel.
Field F was shut down for turnaround maintenance in 2015. After the field was brought back online, one of the production wells (F5) failed to flow. An evaluation of the reservoir, well, and facilities data suggested that there was a gas hydrate blockage in the pipeline. A subsea intervention vessel was then hired to execute a pipeline pigging and clean-out operation, which removed the gas hydrate, and restored oil production from the F5 well. To minimise oil production losses due to flow assurance issues, the asset team evaluated the viability of installing a test pipeline and a second methanol umbilical as facilities enhancement projects.
The pipeline clean-out operation delivered 5400 barrels of oil per day production to the asset. The feasibility study suggested that installing a second methanol umbilical and a test pipeline are economically attractive. It is recommended that the new methanol umbilical is installed and used to guarantee flow from the F5 well and the planned infill production wells. The test pipeline should also be installed and used for new well clean ups, well testing, well sampling, water chemistry analysis, tracer evaluation, and production optimisation.
This paper presents failure diagnosis and flow assurance remediation steps in a producing oil field, and aids the justification of test pipeline and methanol umbilical capacity enhancement projects.
This publication presents the lessons learnt during an operation to remove a hydrate blockage and reinstate oil production from a deep water well offshore Nigeria. It also uses economics to justify facilities projects for hydrate prevention and flow assurance. Field D is a deep water field with sandstone reservoir formations, oil, and gas-cap gas at initial conditions. It has been developed with over 10 subsea production and injection wells tied back to a Floating, Production, Storage, and Offloading (FPSO) vessel.
Field D was shut down for turnaround maintenance during the summer of 2016. After the field was restarted, one of the production wells (D2) failed to flow. An evaluation of the pressure and temperature data suggested that the well had a tubing restriction. This was attributed to hydrate formation and blockage caused by limited methanol injection capacity.
A number of attempts were made to restart the well with no success. A subsea intervention vessel was then hired to execute a clean out intervention operation, which restored oil production from the D2 well. The intervention operation added 26 000 barrels of oil per day production to the asset.
To minimise hydrate blockage and oil production losses, the asset team completed feasibility studies to evaluate the viability of installing a second methanol umbilical and a test/service pipeline. These studied indicated that installing both facilities enhancement projects are economically attractive.
This publication presents the lessons learnt during hydrate formation in a producing oil field, and outlines practical methods that can be used to justify facilities enhancement projects.
The objective of this paper is to provide a review of the evolution of the flow assurance discipline over the years as it applies to the design of gathering and export pipeline systems. In the early days, pipeline design was essentially a job for one engineer when pipelines were on land or in shallow water, not in a new geological province, flowing temperatures / pressures were not abnormal, and had no multi-phase flow or contaminants.
This paper will identify events or circumstances that affected how "~Pipeline Hydraulics" were designed. Flow Assurance Engineering has evolved from two fundamental pillars – thermo-hydraulic analysis of fluid flow in production systems, and production chemistry.
Today, flow assurance engineers in a project not only provide predictions, but also prevention strategies, and remediation methods for: Fluid characteristics Flow hydraulics and thermal behaviors Performance of the production system Guidance of operation strategies Identification and management of solid deposition issues: hydrates paraffins (waxes) asphaltenes scales, etc.
Flow hydraulics and thermal behaviors
Performance of the production system
Guidance of operation strategies
Identification and management of solid deposition issues: hydrates paraffins (waxes) asphaltenes scales, etc.
They interface with multiple disciplines involved with the project, including subsurface, pipeline and risers, subsea hardware, topsides process facilities, chemical vendors, the fluid laboratory, etc.
Beginning in the late 1940s, pipelines began transporting hydrocarbons over long distances onshore (conversion of the Big Inch Crude and Little Inch product pipelines to natural gas service for example) when unforeseen flow problems began to occur. Exploration gradually moved to nearshore drilling, and finally, to shallow water. Additional flow problems increased in complexity and magnitude.
To track how these increasingly complex flow problems affected pipeline design, this paper presents: The evolution of Flow Assurance from simple hydraulics calculations to a well-defined engineering discipline The critical responsibilities in current deepwater development - Greenfield and Brownfield projects The re-shaping of Flow Assurance Engineering by digital revolution and big data technologies The evolution of the discipline applying new technologies to unlock new reserves with longer, deeper tiebacks
The evolution of Flow Assurance from simple hydraulics calculations to a well-defined engineering discipline
The critical responsibilities in current deepwater development - Greenfield and Brownfield projects
The re-shaping of Flow Assurance Engineering by digital revolution and big data technologies
The evolution of the discipline applying new technologies to unlock new reserves with longer, deeper tiebacks