The term sweet spot means multiple things to different people, for some it might be the economically attractive part of the play for others the cheapest part to access, while others consider that it is represented by a unique property of the play. Often people search for a single silver bullet to predict them. Here we define a sweet spot as that portion of the play that has top quartile EUR (Estimated Ultimate Recovery) performance. Such sweet spots are not random but occupy only a small area of the total play. Sweet spots come in two forms, simple and composite. The former are typically the result of stratigraphic features while the later are commonly the result of a combination of multiple geological factors that coincide e.g. maturity, drive energy, etc,. For composite sweet spots the recipe that works in one play may be different from that which works in another. Thus predictive methods that work for one sweet spot may not work for all as the fundamental underlying geological causes can vary and hence the search for silver bullets may be fruitless. Composite sweet spots are by far the most common. In all cases, sweet spots hold the key to creating value in an unconventional plays.
Note submission of parker is subject to Shell publication approval
Dick, K. Christopher (Shell Exploration & Production) | Hnat, James (Shell Exploration & Production) | Cakici, Deniz (Shell Exploration & Production) | Mookerjee, Abhijit (Shell Exploration & Production) | Stephenson, Ben (Shell Canada)
The physics of unconventional reservoir development boils down to two processes - reservoir stimulation during hydraulic fracturing, and fluid recovery during depletion. How these two processes come together and interact with naturally present, pre-existing geological attributes (faults, mineralogy, stresses etc.) to affect well performance is a subject of great interest and fierce debate. At Shell, we have attempted to answer this question by deploying comprehensive instrumented pilot programs that employ various reservoir monitoring technologies including but not limited to microseismic monitoring, chemical tracers, fiber optics, downhole pressure gauges and production logs.
These technologies are often implemented in shale gas (SG) and liquid rich shale (LRS) plays to provide insight into the following:
The above are all important inputs needed to make informed decisions regarding well spacing, well lengths, stage spacing, stage placement, well orientation and well landing - decisions that can challenge or ease the economic feasibility of a project. These data also have the potential to serve as an integrated platform where geologists, geophysicists, production, reservoir and geomechanical engineers can converge to discuss the key uncertainties and issues that affect unconventional reservoir development.
However, in order to properly leverage the power of integrated analysis, we must develop novel and innovative workflows that combine existing geological characterization techniques (3D seismic interpretation, core interpretation and analysis, static modeling etc.) with reservoir monitoring and engineering data.
Optimum well spacing is one of the main development questions in Appalachian Marcellus shale assets. Answering this question requires a good understanding of well-to-well interactions, which is dominated by hydraulic fracture geometry and structural geology (faults, natural fractures, layering, etc.) A comprehensive data gathering exercise and a reservoir characterization study has been in progress since the start of 2012 at a pilot pad. The pilot includes three horizontal producers and a horizontal observation well. Downhole pressure and temperature, DTS, chemical tracer, microseismic, and PLT data were collected during hydraulic fracturing and production of the wells. Later these data were integrated with the existing 3D-seismic, core and log data to construct a subsurface model.
This paper summarizes two aspects of the subsurface characterization work:
1. Integration of data from different sources: Results from each data source are summarized in the first half of the paper. Also, consistency of the results is discussed. Later, well-to-well connectivity and stimulated reservoir volume (SRV) based on pilot data are shown.
2. Dynamic modeling of the pilot: In the second half of the paper, history matching process is presented. It focuses on the integration of static models and observations from pilot data. Practical aspects of the modeling work, such as gridding, representation of SRV, hydraulic fractures, and geological features (natural fractures, faults/lineaments) and model initialization are discussed. At the end, results of the history match study are presented.
Buijse, Marten Adriaan (Shell Exploration & Production) | Tandon, Kunj (Shell Technology Centre Bangalore) | Jain, Shekhar (Shell Technology Centre Bangalore) | Jain, Amit (Shell Technology Centre Bangalore) | Handgraaf, Jan-Willem (Culgi B.V.) | Fraaije, Johannes G. E. M. (Leiden University)
Surfactant formulations are extensively being developed in the oil industry for Enhanced Oil Recovery (EOR) applications. Surfactants suitable for EOR will form an oil-brine microemulsion (µE) with ultra-low interfacial tension (IFT), necessary for
high recovery factors. Experimental screening of surfactants, to identify suitable formulations for reservoir conditions, is a laborious and time consuming process. In this paper we demonstrate an alternative, and novel, molecular modeling approach which is suitable for predicting µE properties and calculating optimum conditions. The molecular modeling simulations are based on the recently developed Method of Moments (MoM). The µE physics underlying the MoM is briefly reviewed in this
In the MoM the bending properties of the interfacial surfactant film are calculated as moments of the lateral stress profile. At optimum salinity the zeroth and first moments of the lateral stress profile are zero and the IFT will reach a minimum. In addition to optimum salinity, the bending rigidity (stiffness) of the surfactant film is another interesting microstructure property. The bending rigidity determines the oil/brine domain size, solubilization and magnitude of the IFT. The bending rigidity is accessible in the MoM via the saddle-splay modulus ks, which is calculated as the second moment of the lateral stress profile. It is shown in the paper how the shape of the lateral stress profile depends on molecular properties of the surfactant and on salinity.
MoM simulations were carried out using the coarse-grained Dissipative Particle Dynamics (DPD) method. This computational approach is highly scalable, while preserving the structural information of chemical components in the system. This makes the method useful while screening the wide design space of possible surfactant-oil-brine combinations. We will discuss the predictive technique and some validation examples of predicting optimum salinity for oil-brine micro-emulsions. We will then demonstrate the effect of surfactant structural parameters like chain length, cosolvent etc. on the optimum salinity of the microemulsions.
Farajzadeh, Rouhollah (Shell Intl. E&P BV) | Ameri, Amin (Delft University of Technology) | Faber, Marinus J. (Shell Intl. E&P BV) | Van Batenburg, Diederik W (Shell Exploration & Production) | Boersma, Diederik Michiel (Shell Intl. E&P BV) | Bruining, J. Hans (Delft University of Technology)
Alkali Surfactant Polymer (ASP) flooding has traditionally been considered in tertiary mode, i.e., after a reservoir has been sufficiently water flooded. In screening studies experiments are usually conducted under two-phase flow conditions, i.e., in the absence of a gas phase in the rock.
In practice, oil reservoirs might contain some gas. In areas in the world, where gas flaring is not allowed and an infrastructure for gas transportation is not present, re-injection of produced gas is a common practice. Moreover, when the reservoir is depressurized below bubble point a gas phase will be created.
To the best of our knowledge, there are no data in the literature concerning the influence of in-situ gas phase (continuous or trapped) on the performance of ASP floods. The main objective of this paper is to evaluate how the presence of a free (non-dissolved) gas phase affects ASP flood performance. To this end, several experiments were carried out to evaluate different conditions, where free gas was present, either flowing or trapped.
We found that the ultimate residual oil saturation in most experiments is similar to the case without gas. When free gas is present in the porous medium, the oil-bank production occurs earlier, because a large fraction of the gas remains trapped and therefore the "effective?? pore volume for liquid flow is reduced. When the gas and the ASP solution are co-injected, the oil is mostly produced in emulsion form as gas enhances mixing of the in-situ fluids. Trapped gas could lead to an efficient oil recovery, depending on the amount of trapped gas: the lower the trapped gas saturation the better the oil recovery.
Couzens-Schultz, B.A. (Shell International Exploration and Production) | Axon, A. (Shell China Exploration and Production Co. Ltd.) | Azbel, K. (Shell International Exploration and Production) | Hansen, K.S. (Shell International Exploration and Production) | Haugland, M. (Shell International Exploration and Production) | Sarker, R. (Shell International Exploration and Production) | Tichelaar, B. (Shell Egypt N.V.) | Wieseneck, J.B. (Shell Exploration and Production) | Wilhelm, R. (Shell Exploration and Production) | Zhang, J. (Shell Exploration & Production) | Zhang, Z. (Shell International Ltd.)
Understanding pore pressure prediction in unconventional plays is important for executing a safe drilling strategy and for accurate production modeling. Experience from several unconventional plays highlights key aspects of pore pressure prediction work that are different from conventional exploration settings. In conventional exploration, the most common source of overpressure is disequilibrium compaction, where porosity is preserved in mudrocks as pore fluids take on additional overburden load. Traditional petrophysical methods use resistivity, sonic and density data to measure porosity and associate it with vertical effective stress (VES), which is overburden minus pore pressure. In unconventional plays, secondary pressure mechanisms and uplift require other methods because of two influences on pore pressure: (1) hydrocarbon generation and (2) variations in burial and uplift history. Both of these situations mean that the relationships between vertical effective stress (VES), velocity, density and resistivity will follow unloading paths, not compaction trends. The unloading paths vary depending on the amount of hydrocarbon generated and the amount of uplift. In organic-rich sections, an additional complication arises because pore pressure cannot be de-convolved from total organic carbon (TOC) and gas effects on shale compressional velocity and resistivity. In conventional settings, fluid gradients and contacts are used to translate measured pressure data from one location to another. In unconventional tight reservoirs, the fluids are not connected and this method will not work. Pressure data must be inferred from drilling event and diagnostic fracture injection test interpretations, and a different way to translate data between locations is required. The majority of pressure data in unconventional reservoirs shows that often, the way to translate pressure information from one location to another in the same tight rocks is to use a constant VES. This method combined with understanding variations in uplift history and hydrocarbon generation has been used to successfully predict pressure ranges in multiple unconventional plays.
Unconventional resources plays in shale and tight rocks have become a substantial resource in North America. They are now rapidly being explored and developed outside the United States and Canada in a trend that will likely continue to grow. To economically develop these plays, wells must be drilled as cost effective as possible. To produce from these plays and forecast production, the mechanical properties of the rocks and their stress conditions need to be understood to best stimulate and complete the wells. Pore pressure prediction is integral to both of these activities.
A tremendous amount of effort has been placed on subsea cap and containment in order to demonstrate the exploration and production industry's response to a subsea well control event. This paper will focus on the methods and processes planned to contain a subsea blow out beneath a Tension Leg Platform (TLP) in deepwater Gulf of Mexico. Response to a well control event of this type is divided into 3 major categories: 1) TLP Health and Stability Monitoring - Understanding the structure stability is key in planning the response and determining the time allowed to deploy containment assets, 2) Debris Clearing- a path must be cleared into the well pattern horizontally and vertically for the capping stack to be deployed and 3) Stack Deployment - with the TLP still floating above the well pattern the stack must be deployed laterally under the facility and onto the well. Several challenges were encountered during the design and approval of this containment method, leading to the development of alternative capping strategies, purpose built capping stacks, installation of permanent monitoring / response equipment and use of Delmar's Heave Compensated Landing System (HCLS) to accomplish these critical subsea tasks.
Copyright 2013, SPE/IADC Drilling Conference and Exhibition This paper was prepared for presentation at the SPE/IADC Drilling Conference and Exhibition held in Amsterdam, The Netherlands, 5-7 March 2013. This paper was selected for presentation by an SPE/IADC 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 Society of Petroleum Engineers or the International Association of Drilling Contractors and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers or the International Association of Drilling Contractors, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers or the International Association of Drilling Contractors is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE/IADC copyright. Abstract After a successful pilot application in the Haynesville Shale, Shell Upstream Americas is currently taking steps to conduct all of its directional drilling, MWD/LWD and geosteering operations in the Americas and beyond from remote drilling centers.
The use of multi-fracced horizontal well technology in unconventional gas and liquid rich reservoirs is one of the key reasons for the recent success in the exploitation of Unconventional Resources. These multiple fractures are placed in many stages along the horizontal well using diverse completion technologies. Yet, the understanding of fracture growth mechanics and the optimum fracture placement design methodology are still preliminary. Recent advances in computational mechanics and the development of appropriate stimulation modeling technology will further nurture innovation and press forward much needed optimization of the Completion and Stimulation technology in multi-fracced horizontal wells.
This paper contains two key components. Firstly, an analytical model is used to highlight some of the salient features of multiple hydraulic fractures interaction. The advantage of an analytical model is that it provides immediate insights into the controlling parameters and steer further numerical analysis on stimulation optimization. Secondly, an idealized 2D numerical model is employed to illustrate fracture interference and interaction - not just between fractures that are pumped simultaneously, but also multi-stage fractures interaction and even potentially well-to-well interaction. Most of this interaction can be attributed to the fact that we are placing fractures in extremely tight formation (shales) and most fracture stimulation operations are conducted and completed within a time frame that is shorter than the time needed for frac fluid to completely leak-off and the resultant in-situ stress perturbation to dissipate. The understanding of subsurface fractures interaction will impact on surface simultaneous operation planning and execution in full scale development of unconventional gas and oil.
Ridley, Katrina M (Shell Exploration & Production) | Jurgens, Matthew (Shell Exploration & Production) | Billa, Richard J. (Shell Exploration & Production) | Mota, Jose F. (Shell Exploration and Production)
While there was no flare during drilling, the flare at bottoms up at TD averaged between 10 and 20 feet. Previous experience in the Eagle Ford and other tight gas plays showed this level of gas to be manageable with conventional Rotating Control Device, RCD, and a mud gas separator. There were some losses encountered during the initial 5 ½" production casing cement jobs with a two-slurry design of top of cement at surface and a 12.7 ppg lead and 16.4 ppg tail. This was attributed to formation weakness in the Olmos sand which occurred from 5300 - 6700 ft TVD. Equivalent circulating density, ECD, simulations established this formation as a potential weak point in the production section with an estimated fracture strength between 13 and 14 ppg EMW across the field. Drilling - Phase 2: Establishing Boundaries Wells were initially drilled with a mud weight between 11 ppg and 12 ppg, well below the established upper limit of the Olmos sand. A trial was initiated to determine the lower limit for mud weight in an effort to increase rate of penetration and reduce drill time.