Pietraszsek-Mattner, Sarah (ExxonMobil Exploration Company) | Barron, James W. (ExxonMobil Upstream Research) | Myers, Rodrick D. (ExxonMobil Upstream Research) | Moreton, David J. (ExxonMobil Exploration Company) | Sempere, Jean-Christophe (ExxonMobil Upstream Research)
With the recent downward pressure on oil and gas prices, the oil and gas industry is operating in a reduced capital environment and is optimizing expenditures throughout the lifecycle of an oil and gas asset. In order to stay competitive, successful companies need to develop the next generation of technologies to enhance their abilities to be more selective in exploiting the reservoirs that underpin a project. In the past, the evolution of 3D and 4D seismic acquisition and enhanced seismic imaging techniques reduced exploration risk through the remote sensing of trap geometries, reservoir properties, and fluid presence, where favorable conditions existed. In higher-risk plays, such as those that depend on the existence of connected natural fracture networks to achieve economic flow rates, the ability to predict the presence, orientation, extent, and relative intensity of these fracture systems is necessary to improve the overall success in intersecting the highest natural fracture density and most productive reservoirs. Traditionally, the impact of natural fractures on reservoir performance has been analog-based and scaled to match production data. A new process-based numerical modeling technology has been developed that predicts the formation of natural fracture networks from structural history and geomechanics. This prediction is then calibrated to fracture data collected from image logs, core and dynamic wellbore performance data. Utilizing this field-wide spatial distribution of fracture connectivity can narrow investment uncertainty by optimizing the number and position of future appraisal, production and injection well locations.
Romer, Michael C. (ExxonMobil Upstream Research) | Brown, Matthew (XTO Energy) | Ainsworth, Nick (XTO Energy) | Rundberg, Oran (XTO Energy) | Bolt, David J. (Cormorant Engineering) | Bolt, Travis (Cormorant Engineering) | Tolman, Randy C. (RC Tolman LLC)
A novel hydraulically powered, self-reciprocating valve pump (SRVP) was piloted in a western Colorado gas well for deliquification operations. The objective was to pump liquids from a deep gas well and later retrieve and redeploy the SRVP without a workover rig. This paper will describe the SRVP technology, areas of applicability, and pilot program, including the completion design, deployment/retrieval workovers, performance, teardowns, learnings, and future plans.
Gas-production wells tend to load up with produced or condensed liquids that create an impediment to flow and reduce or stop gas production. Pumps are typically used when the reservoir pressure is too low for less-intrusive artificial-lift (AL) methods or when significant amounts of liquid must be removed. Pumps can suffer from reliability issues and considerable installation/deployment costs because a workover rig is typically required for intervention. Unfavorable producing conditions and tortuous wellbore trajectories tend to further decrease run lives. These issues can make economical hydrocarbon production impossible. The SRVP was developed to overcome these challenges.
The SRVP is installed downhole inside a concentric tubing string, and is powered by injecting a high-pressure liquid. The injected (power) fluid causes the SRVP to reciprocate, driving a piston pump to produce formation fluids and to power fluid back to the surface up the concentric-string/production-tubing annulus. The removal of the produced fluids decreases the backpressure on the formation, enabling gas production up the casing. Because there is no mechanical linkage to the surface for pump operation, the SRVP can be deployed in highly deviated and/or small-diameter wells with which standard AL methods would struggle. In addition, the SRVP is designed to be pumped into and out of the well after initial installation, greatly reducing deployment costs.
Three industry-first SRVPs were installed consecutively in a concentric flush-joint tubing string, and were powered with a compact surface pumping unit. The SRVP proved the ability to lift 20 to 40 BFPD net liquids up the concentric-string/production-tubing annulus from more than a 12,000-ft vertical depth while gas was produced up the casing. The SRVP was retrieved and redeployed several times either hydraulically and/or with slickline (SL). System design, operation, and performance were continuously improved through the duration of the pilot program. Run life steadily increased to more than 50 days with the third installation.
Krebs, Jerome (ExxonMobil Upstream Research) | Ober, Curtis (Sandia National Laboratories) | Smith, Thomas (Sandia National Laboratories) | Overfelt, James (Sandia National Laboratories) | Collis, S. (Sandia National Laboratories) | Von Winckel, Gregory (Sandia National Laboratories) | Van Bloemen Waanders, Bart (Sandia National Laboratories) | Downey, Nathan (Sandia National Laboratories) | Aldridge, David (Sandia National Laboratories)
We present a synthetic study investigating the resolution limits of Full Wavefield Inversion (FWI) when applied to data generated from a visco-TTI-elastic (VTE) model. We compare VTE inversion having fixed Q and TTI, with acoustic inversion of acoustically generated data and elastic inversion of elastically generated data.
Presentation Date: Tuesday, October 18, 2016
Start Time: 1:00:00 PM
Presentation Type: ORAL
Current industry practice in flexible pipe tensile armor wire fatigue testing involves use of un-corroded specimens; however, if the armor wires in a flexible are prone to pitting corrosion during service, this adds a new dimension to the fatigue life consideration which is the focus of this paper. The paper presents a methodology to consistently evaluate fatigue lives of armor wires with pitting corrosion. Described herein is a methodology to create corrosion pits on armor wires and the results from a fatigue test program involving Non-Pitted and Pre-Pitted specimens.
Flexible risers, used in the offshore Oil and Gas industry for hydrocarbon production and transportation, offer many advantages over steel pipes- the key one being their higher structural flexibility, and hence greater ability to accommodate dynamic loads in hostile offshore environments, especially those induced by vessel motions. A typical flexible riser consists of two sets of tensile armor wires helically wound around the inner pipe layers to provide structural strength for weight and dynamic loads. Fatigue of tensile armor wires used in flexible risers is often a consideration, from a design perspective as well as a remnant-life-assessment perspective.
The multi-layered flexible pipe cross section is a complex structure that can create unique operating conditions for the carbon steel armor wires in the annulus between the internal and external sheath. The annulus, which houses the armor wires, comprises the volume between the pressure sheath and the external sheath. The structure of flexible pipes is designed to prevent direct contact between the steel wires and external sea water, and between the steel wires and the internal produced fluid. Presence of liquid water or seawater in the annulus together with corrosive gases such as Carbon Dioxide (CO2) and/or Hydrogen Sulphide (H2S) can lead to wire corrosion; and under certain conditions, the presence of corrosive fluids in the annulus is possible either due to accidental damage of the outer sheath allowing seawater to enter the annulus, or due to condensation of diffused fluids from the inner bore. The corrosion in the annulus can manifest itself as general and pitting corrosion of the armor wires if the wires are not designed to resist such corrosive conditions in the annulus. Pitting corrosion is of particular interest since the pits, which can be as deep as 0.1 mm with aspect ratios in the range of 10 to 50, have the potential to initiate Stress Corrosion Cracking (SCC), Sulfide Stress Cracking (SSC) or Hydrogen Induced Cracking (HIC) in flexible flowlines under static load conditions, or fatigue cracks under dynamic load conditions in flexible risers. This assumes more importance when one considers the fact that thirty five percent of all flexible pipe damage incidents reported worldwide, according to the 2010 Sureflex JIP, is due to external sheath damage and annulus flooding.
Nassir, M. (Taurus Reservoir Solutions) | Walters, D. (Taurus Reservoir Solutions) | Yale, D. P. (ExxonMobil Upstream Research) | Chivvis, R. (BP Exploration (Alaska) Inc.) | Turak, J. (BP Exploration (Alaska) Inc.)
Optimizing the efficiency of the waterflood displacement process in heavy oils is critical to reaching the oil recovery goals. However, in the process of finding an economic and stable throughput for the process, in some cases significant sand production and generation of wormholes have resulted in premature water breakthrough and channelling destroying volumetric efficiency. In order to understand such events, a simulation study using a coupled reservoir and geomechanical simulator was used to determine the physics controlling the initiation and propagation of dilated zones resulting from sand production giving the premature breakthrough. An attempt was made to identify the importance of well configuration and what operating constraints can be altered to reduce the risk of these breakthrough events.
The complex physics of sand production during oil recovery requires it to be modeled as a coupled process: multiphase fluid flow causing transient pressure gradients and geomechanics to calculate the resultant stress variation, permeability enhancement and shear/tensile failure around the induced dilated zone and finally coupling failure criterion for the dilated zone propagation combining pressure gradient and effective stress. A force balance criterion calculates the threshold fluid pressure gradient for sand mobilization based on the effective confining stresses in each numerical element. The stress variation across the loosely supported sand body (damage zone) at the edge of a dilated zone is captured by an elasto-plastic constitutive model using a Mohr-Coulomb shear failure surface combined with softening of the Young's modulus.
The application of the coupled simulator in modeling waterflooding reveals critical insights regarding the significance of different factors contributing to the sand production problem. Multiphase flow, over vs. under-injection, and inter-well pressure gradient effects are critical to controlling the sand production initiation and evolution. Gas liberation below bubble point pressure conditions causes excessive pressure gradient and increases the possibility of sand production. The oil/water relative permeability impact emerges if the mixture mobility at a certain fraction is lower than the end points. As dilated zone geometry appears to follow the weakest zones often associated with high permeable layers; it highlights the significance of the reservoir heterogeneity in contributing to the sand production problem. The results of the current study add understanding to the significance of different mechanisms contributing to sand production and may be used to help mitigate the premature breakthrough problem observed in many waterflooding operations.
Gist, Grant (ExxonMobil Upstream Research) | Ciucivara, Adrian (ExxonMobil Upstream Research) | Houck, Rich (ExxonMobil Upstream Research) | Rainwater, Mike (ExxonMobil Upstream Research) | Willen, Denny (ExxonMobil Upstream Research) | Zhou, Jin-Juan (ExxonMobil Upstream Research)
Summary Inversion of a CSEM survey over a seismically mapped prospect in the Orphan Basin shows high vertical resistivity in the prospective fault block. The combination of high resistivity with low acoustic impedance below the target horizon was interpreted to indicate hydrocarbon presence, but a well found no hydrocarbons and low vertical resistivity. Detailed analysis of the well logs shows that the high vertical resistivity seen on the CSEM inversions was caused by thin, carbonate-cemented layers with very high resistivity that was underestimated by the vertical resistivity log. Probabilistic rock physics modeling of the depth interval around the target reservoir shows that, while the observed vertical resistivity is consistent with the well outcome (wet reservoir), it is more supportive of hydrocarbon bearing reservoir. Introduction Marine CSEM surveys typically focus on finding regions of high vertical resistivity that are expected from a resistive hydrocarbon reservoir (Constable, 2010).
Probabilistic rock physics modeling provides a way of interpreting CSEM-derived resistivities that accounts for the ambiguous relationship between resistivity and hydrocarbon presence. A synthetic data example illustrates how the interpretation of a resistivity anomaly depends on prior knowledge of rock and fluid properties. Because the depth interval sensed by CSEM is typically much larger than the net thickness of the target reservoir, the assumed properties of the non-net can have a large impact on the interpretation.
Roland Moreau, ExxonMobil Upstream Research Roland Moreau, SPE, is the Health, Safety, Security, and Environment manager for ExxonMobil Upstream Research Company. He also serves as vice president of ExxonMobil Research Qatar Limited in Doha. He began his career with Exxon Company USA as a project engineer at the Bayway refinery in New Jersey in 1981. Since that time, he has held various technical, supervisory, and managerial assignments for Exxon, and then ExxonMobil. Moreau is SPE's technical director for Health, Safety, Security, Environment, and Social Responsibility, and has been active in developing its HSSE-SR's programs and conferences.
Gupta, Jugal K. (Exxon Mobil Corporation) | Albert, Richard Alan (ExxonMobil Upstream Research Co.) | Zielonka, Matias G. (Exxon Mobil Corporation) | Yao, Yao (ExxonMobil Upstream Research Co.) | Templeton-Barrett, Elizabeth (ExxonMobil Oil Corp.) | Jackson, Shalawn K. (ExxonMobil Upstream Research Co.) | El-Rabaa, Wadood (ExxonMobil Upstream Research) | Burnham, Heather Anne (XTO Energy) | Choi, Nancy Hyangsil (XTO Energy)
Fracture nucleation and propagation are controlled by in-situ stresses, fracture treatment design, presence of existing fractures (natural or induced), and geological history. In addition, production-driven depletion and offset completions may alter stresses and hence the nature of fracture growth. For unconventional oil and gas assets the complexity resulting from the interplay of fracture characteristics, pressure depletion, and stress distribution on well performance remains one of the foremost hurdles in their optimal development, impacting infill well and refracturing programs.
ExxonMobil has undertaken a multi-disciplinary approach that integrates fracture characteristics, reservoir production, and stress field evolution to design and optimize the development of unconventional assets. In this approach, fracture modeling and advanced rate transient techniques are employed to constrain fracture geometry and depletion characteristics of existing wells. This knowledge is used in finite element geomechanical modeling (coupling stresses and fluid flow) to predict fracture orientation in nearby wells.
In this paper, an integrated methodology is described and applied to a shale gas pad as a case study. The work reveals a strong connection between reservoir depletion and the spatial and temporal distribution of stresses. These models predict that principal stresses are influenced far beyond the drainage area of a horizontal well and hence can play a critical role in fracture orientation and performance of neighboring wells. Strategies for manipulating stresses were evaluated to control fracture propagation by injecting, shutting-in, and producing offset wells. In addition, we present diagnostic data obtained from the pad that demonstrates inter-well connectivity and hydraulic communication within the pad. The workflow presented herein can be used to develop strategies for (1) optimal infill design, (2) controlling propagation of fractures in new neighboring wells, and (3) refracturing of existing wells.
Blunt, J.D. (ExxonMobil Upstream Research) | Mitchell, D.A. (ExxonMobil Upstream Research) | Matskevitch, D.G. (ExxonMobil Upstream Research) | Younan , A.H. (ExxonMobil Upstream Research) | Hamilton, J.M. (ExxonMobil Upstream Research)
Copyright 2012, Offshore Technology Conference This paper was prepared for presentation at the Arctic Technology Conference held in Houston, Texas, USA, 3-5 December 2012. This paper was selected for presentation by an ATC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied.