Exxonmobil Upstream Research Company

David P Yale

Zhengyu Zhang

Paul M Chaikin

Arnold P Kushnick

Sheng-Yuan Hsu

Nazish Hoda

Steven W Meier

David Craig Dalrymple

Andrey A Troshko

Sergio A Leonardi

Hemantkumar R Sahoo

David J Moser

William A Symington

Neal L Adair

Thomas J Boone

Richard J Smith

Ganeswara Rao Dasari

Jianlin Wang

Eric Herbolzheimer

Ganeswara R Dasari

A method of backfilling a subsurface formation that includes forming a mixture tailings from at least two sources that have particles with different size distributions. The water content of the mixture is varied to control the rheology of the mixture. The mixture is injected through one or more pipes into a target location, such as a subsurface formation.

Systems and methods for injecting a particulate mixture

Methods for modeling subsurface reservoirs are provided. In at least one embodiment, the process includes building a numerical model of a reservoir having at least one injection well and at least one producing well, and incorporating at least one of an Eulerian boundary condition (EBC) into each of the at least one injection well and at least one producing well, an advanced constitutive model (ACM) int the reservoir, and an adaptive re-meshing technique (ART) into the reservoir model. Then generating a simulation result from the integrated reservoir model, wherein the simulation result includes at least a volume of produced fluids and produced particulate solids from the reservoir, a volume of injected fluids and injected particulate solids into the reservoir, and a simulation of movement of at least a volume of particulate solids and fluids in the reservoir.

Sand and fluid production and injection modeling methods

Methods for hydrocarbon recovery from a subsurface formation include removing a mixture comprising hydrocarbons and particulate solids from a first formation. At least a portion of the hydrocarbons are separated from the particulate solids. The particulate solids are separated into a plurality of streams. A mixed slurry comprising a first portion of the plurality of streams is injected through a first pipe into the first formation. A waste stream comprising a second portion of the plurality of streams is injected through a second pipe into a second formation. The first formation and the second formation lie in a substantially vertical line.

Systems and methods for dual reinjection

Methods and apparatuses for recovering heavy oil that, at least in one embodiment, include conditioning a reservoir of interest, then initially producing fluids and particulate solids such as sand to increase reservoir access. The initial production may generate high permeability channels or wormholes in the formation, which may be used for heavy oil production processes such as cold flow (CHOPS) or enhanced production processes such as SAGD, or VAPEX.

Methods for application of reservoir conditioning in petroleum reservoirs

In at least one specific embodiment, a method for recovering heavy oil includes accessing, from two or more locations, a subsurface formation having an overburden stress disposed thereon, the formation comprising heavy oil and one or more solids. The formation is pressurized to a pressure sufficient to relieve the overburden stress. A differential pressure is created between the two or more locations to provide one or more high pressure locations and one or more low pressure locations. The differential pressure is varied within the formation between the one or more high pressure locations and the one or more low pressure locations to mobilize at least a portion of the solids and a portion of the heavy oil in the formation. The mobilized solids and heavy oil then flow toward the one or more low pressure locations to provide a slurry comprising heavy oil and one or more solids. The slurry comprising the heavy oil and solids is flowed to the surface where the heavy oil is recovered from the one or more solids. The one or more solids are recycled to the formation.

Slurrified heavy oil recovery process

A method for producing a substantially calibrated numerical model, which can be used for calculating a stress on any point in a formation, accounts for a formation's geologic history using at least one virtual formation condition to effectively 'create' the present-day, virgin stress distribution that correlates, within acceptable deviation limits, to actual field stress measurement data obtained for the formation. A virtual formation condition may describe an elastic rock property (e.g., Poisson ratio, Young's modulus), a plastic rock property (e.g., friction angle, cohesion) and/or a geologic process (e.g., tectonics, erosion) considered pertinent to developing a stratigraphic model suitable for performing the desired stress analysis of the formation.

Method for calibrating a model of in-situ formation stress distribution

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Milford, NJ, United States of America

David P Yale