In recent years, the Oil & Gas industry has struggled due to the low hydrocarbon prices. In this context, E&P firms have responded by optimizing their asset portfolio with focus on prospects with the lowest possible financial and technical risks. Since this process has seriously affected countries with emerging hydrocarbon plays and/or relatively low explored geology, government incentives play a pivotal role to mitigate this pessimistic trend. To understand their benefits, this paper presents a methodology to value hydrocarbon prospects using a real option formulation that properly incorporates government incentives such as royalty relief and royalty rate structures that vary with production volumes and prices.
This work links valuation and incentives by using functions that depends linearly on relieved and produced volumes and non-linearly on price. These variable royalty schemes behave similar to bull spreads (financial derivative tool), limiting the upside and downside risk of both government and company take due to hydrocarbon prices and production volumes. Then, we incorporate these functions into the general real option formulation and numerically solve the yielded equations using finite differences methods.
For illustration purposes, the proposed approach is applied to a hypothetical field with an exponential decay production curve. We compare the impact of government incentives for both the prospect value and the optimal investment rule. As observed, these incentives have two merits: to positively influence the economic attractiveness of future developments by compensating investors for their high-risk exposure and to allow an optimal government take in an unfavorable price environment.
We observed that before lease expiration, the real option approach assesses the timing option. Consequently, this approach yields higher values than the NPV analysis since delaying the project execution can be more valuable than the immediate option exercise. Moreover, depending on the financial and volume parameters, intermediate waiting areas might appear between exercise regions. Hence, the methodology proposed captures not only the flexibilities available for an E&P firm that holds a lease, but also the economic benefit of the incentives and their impact on the investment rule.
In summary, the novelty of this work is to propose a general methodology that includes government incentives in the economic analysis of hydrocarbon asset developments using real options. This methodology captures the flexibilities available for managers to respond to hydrocarbon price uncertainty. Moreover, we also propose a new royalty rate scheme that resembles bull spreads. This scheme allows investors to capture the upside of production and prices, and optimizes the government take.
Significant gas discoveries have been made in deep waters off the coast of Tanzania this decade. Operator Equinor (previously Statoil) with co-venturer ExxonMobil have drilled 15 exploration and appraisal wells in Block 2 about 100 km from the shore in the southern part of the country. The objective is to develop gas resources for a large LNG project. This paper focuses on the various discoveries made and the subsurface understanding gained over the last years.
The reservoirs are all deposited as turbiditic sandstones in different geologic periods (Cretaceous to Miocene), and have a long and complicated geological history. Heavy tectonic activity including development of pop-up structures along a major strike-slip system, has impacted the depositional environment. Since some of the reservoirs have significant internal faulting, methods to analyze fault transmissibility have been key. The seismic quality is generally good, and in certain reservoirs even good enough to directly use seismic inversion dataset to map the structure more accurately. The exploration and subsurface teams worked together in improving the development concept and minimizing risk.
The youngest reservoir (Miocene) has excellent reservoir properties but special challenges with shallow overburden with top reservoir 400-500 m below the seafloor. Several studies have been completed to ensure that production wells can be safely drilled and produced during reservoir depletion, and that the reservoir seal has full integrity.
In deep water oil and gas developments it is important to demonstrate large, continuous flow units with good flow properties before investment decisions. For the Block 2 gas reservoirs understanding the aquifer strength is important for designing wells so that water production can be avoided. Detailed aquifer modeling has been made for all the main reservoirs. Modelling showed risk of water production for one of the reservoirs; however, it is expected that this risk can be mitigated by placing the planned producers high on the structure.
Deep seabed canyons are present in the area and these give important constraints on drilling locations and subsea layout including the major gas pipeline to shore. The field development is planned as a subsea-to-shore development without any fixed installations offshore. To predict the dynamic performance of such a huge and complex production system, extensive flow assurance studies have been completed.
The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC.
Accessed January 5, 2018 Peters, K.E., 1986, Guidelines for evaluating petroleum source rock using programmed pyrolysis: American Association of Petroleum Geologists Bulletin, v. 70, p. 318-329.
Copyright 2018, Unconventional Resources Technology Conference (URTeC) This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited. Abstract Standard seismic/ acoustic log Pp prediction techniques developed for young sediments in offshore basins are not very effective in unconventional reservoirs. The age and lithification of shale reservoirs, the variability in lithology, and different overpressure generation mechanisms and basin histories all lead to poor quality predictions using standard Eaton or Bowers methods. But Pp prediction remains important in unconventional reservoirs due to the correlation between overpressured areas and productivity, and the correlations between thermal maturity and pore pressure. We have developed a method that extends the theoretical basis of the Eaton and Bowers methods to the geologic and basin history conditions of unconventional reservoirs. The method has been developed using standard log suite along with dipole acoustic logs.
This paper highlights the use of integrated project management techniques, as well as innovative drilling fluids technology, to safely achieve drilling objectives on a frontier exploratory, ultra-deepwater project offshore Uruguay. Drilling in a frontier offshore area adds layers of complexity due to inherent uncertainties and risks associated with these types of operations. The use of project management techniques, combined with application of novel drilling fluids technologies, served to mitigate and reduce project risks. Preparation for this well included regulatory review and HSE compliance procedures, facilities and logistics planning, the operator's understanding of the well complexities, selection of experts for each aspect of the operation, and contingency planning to include displacement and emergency disconnect. A thorough and comprehensive readiness review, coupled with communications processes, reinforced the project management loop. Critical path management and efficiencies of drilling operations dictated managing the logistics of mixing large volumes of drilling fluid at multiple locations. The well design program considered the possibility of encountering extreme sediment compaction arising from mass transport complexes (MTC) in the riserless interval. MTCs are a recognized geologic phenomenon and are typically avoided when drilling in deepwater areas of the world.
Current reservoir modeling strategies attempt to characterize the discrete fracture network (DFN) around producing wellbores to better predict both short-and long-term production levels and estimated ultimate recovery. A variety of data sources are used in describing the DFN, including image logs, petrophysical logs, geologically mapped fractures in the region (when available), and regional stress information. For hydraulic fracture stimulations, there is also microseismic data recorded during the stimulation of some wells. The event distribution obtained through microseismic monitoring gives a sense of where fracturing is occurring and how the stimulation progresses from the treatment zone into the reservoir. By using a multi-array distribution of sensors, seismic moment tensor inversion (SMTI) analysis may be performed for microseismic data, providing direct evidence of the DFN stimulated during completion activities. By performing this advanced analysis, a microseismic dataset includes the location, size, and orientation of stimulated fractures, allowing for detailed characterization of the DFN. This paper describes a methodology for characterizing a DFN observed through microseismic monitoring, which is illustrated by application to an example dataset from a North American shale play. By examining relationships between fractures and extracting statistical trends from the distribution of fractures, we arrive at a useful multifaceted description of the DFN which provides improved input data for reservoir modeling and allows a better understanding of the changes in the reservoir due to stimulation.
ABSTRACT: Discrete Fracture Network (DFN) models have advanced considerably, yet challenges remain for capturing attribute variation and uncertainty across scales. We highlight problems using examples from shale hydrocarbon reservoirs, and propose methods to tackle them. Adequate treatment of spatial organization is perhaps the most problematic gap in many DFN models. Analysis of spatial organization in horizontal image logs using a newly developed method yields insight on how to populate models by recognizing distinct patterns of clustering or even spacing. Fracture fill is absent or inadequately treated in most DFN models. We show recent progress on fill prediction, how fill history modifies fracture network flow characteristics and patterns, and how sealed fractures may govern potential interactions with hydraulic fractures. Heights and lengths remain difficult or impossible to measure in the subsurface and challenging to obtain from outcrops. To guide DFN construction, outcrop studies must extract meaningful length data and geomechanical models need to model the range of fracture sizes in 3D, simulate interfaces, and account for cement.
Geochemical analysis of rocks is fundamental to the understanding of geology and earth sciences. X-ray dispersive spectrometry and other automated techniques are increasingly being used to determined and quantify the abundances of the major, trace elements and other rock properties. This study utilized a combination of dispersive spectrometric techniques (MicroXRF) and impulse rebound hammer method to establish links between geochemical and mechanical properties of rocks through a non-destructive method. MicroXRF has high resolution and can detect trace elements within the parts per billion range. The micro-rebound hammer was used to generate a reduced Young's modulus (E*), which gives a measure of the rock strength with negligible impact on the rock itself.
In order to explore, visualize and understand the dataset generated, principal component analysis (PCA) was applied to emphasize variation and bring out strong patterns in the dataset. The first two dimensions of PCA express 57.09% of the total dataset inertia; that means that 57.09% total variability in the data is explained by the planes/dimensions. The first dimension, which showed a strong positive correlation to clay forming minerals and rock strength, was tentatively identified as the clay gradient. The second dimension describes diagenetic alteration processes responsible for the enrichment of elements such as Ni, Mo etc. Further, a positive correlation was established between E* and four elements Cobalt (Co), Strontium (Sr), Titanium (Ti), and Zircon (Zr). Remarkably, Silicon (Si) had a negative correlation with all elements but positive correlation with porosity and permeability. We therefore identified Co, Ti, Sr, and Zr as proxy for the determination of rock strength specific for studied samples and proposed a workflow based on our sequences of analysis and interpretation. Furthermore, we identified four chemo- mechanical facies through hierarchical clustering of the product of the PCA.
This presented methodology could be specifically useful for geomechanical characterization of rocks; a key requirement needed for in-situ stresses estimation, wellbore stability analysis, reservoir stimulation and compaction, pore pressure prediction, and more importantly for characterizing drill cuttings where size and time are limiting. Drilling operations require constantly evolving cost effective and time efficient techniques, the proposed workflow will serve these purposes i.e. rapid determination of elemental composition (microxrf) coupled with E*will give a reliable proxy for rock strength. The technique can be applied to, drill cuttings, slabs and whole core directly without prior sample preparation.
Geomechanical characterization of subsurface rocks is important for many applications throughout the asset life cycle such as borehole instability, pore pressure prediction, seal breach and fault reactivation, drill bits and drilling parameters selection, sand production, hydraulic fracturing, and reservoir compaction (Meyers et al., 2005; Klimentos, 2005; Germay et al., 2017). A key component of Geomechanical characterization is the model calibration with reliable core data. Typically, core data calibration is performed using triaxial tests data output, such as the uniaxial compressive strength (UCS) and elastic properties of rocks (Young's modulus, Poisson's ratio, etc.), that are empirically linked to wireline data. Sample availability, representativeness, time, and cost are problems associated with core-based rock measurements for mechanical properties [3; 4]. There is also the issue of uncertainty associated with upscaling laboratory generated data with wireline data. Core-based measurement output is usually very limited, hardly constitutes statistically representative data as compare to large data from wireline logs, making it difficult to generate a reliable empirical correlation. Another issue is the inherent heterogeneity in rocks, which varies from nano to field scales. This makes establishment of empirical relationship between scattered core data and wireline data a subjective task. Even rocks that appear identically twin in bulk properties can vary widely in microstructure. Characterizing such reservoir-scale heterogeneities requires statistically representative data and the problems associated with core-based measurement make such substantial number of data points requirement an abominable.
The oil and gas production landscape in North America has seen a paradigm shift since the collapse in oil prices in 2014. Although prices remain challenging, several operators have managed to sustain the relatively long period of low margins through some aggressive approaches. This paper inspects changes in operating strategies and field development plans across all oil-rich basins in the US Rocky Mountain fields and how operators have used a combination of low oilfield service prices, high-graded well locations, and incremental fluid/proppant volumes to increase production.
The paper investigates the transformation in operating philosophies since 2014 in four oil-rich basins in the Rocky Mountain region—Williston, Denver-Julesburg (DJ), Uinta, and Powder River. The Bakken formation in the Williston basin represents one of the best-quality rocks in all of North America. However, high oil-price differentials and well costs have made it difficult for drilling to remain profitable. The core of the DJ basin (Wattenberg) has one of the lowest break-even prices in the region, and rig count continues to increase as operators start seeing signs of recovery in the market. The Uinta basin, although relatively small in size, has shown tremendous return potential in the form of multiple stacked pays and promising production results. The Powder River basin poses one of the toughest operational environments in the region owing to wildlife stipulations, harsh weather, and deeper targets.
High-graded well locations in the Bakken are limited to few fields, which limits the scope of expansion in the current oil price environment. The DJ basin is challenged with high-density well spacing; estimated ultimate recovery (EUR) per drilling spacing unit (DSU) continues to increase, but EUR per well has gone down by as much as 60%. In the Uinta basin, formations never known to be continuous in the Green River group have shown significant return potential. The Powder River basin has recently attracted large investments from major independent operators as they tackle drilling challenges associated with abrasive rocks and testing optimum lateral landing points.
Case studies show how operating strategies have changed with changes in oil prices. The Bakken and DJ basins are relatively mature, and as drilled-but-uncompleted (DUC) inventory continues to increase, depletion from existing wells and interference between fractures is impacting production from new wells. The Powder River basin is still in the exploratory phase, and operators are still working on reducing well-costs, optimizing fracturing-fluid/proppant volumes, and examining productivity of other target rocks. The Uinta basin is in the early phases of expansion, with many of the fields still being explored for scalability. Changes in production maps and completion trends provide a comprehensive understanding of how these variables have impacted oil output from the region since 2012.