Mobil Oil Corporation

Alvin S Cullick

Randy D Hazlett

Bert J Warner

Robert E Roach

Melwyn L Mathis

Sriram Vasantharajan

Mark W Dobin

Maiquel Querales

Rama K Vellanki

Gustavo Carvajal

Jose Rodriguez

There is disclosed herein a systematic, computationally-efficient, two-stage method for determining well locations in a 3D reservoir model while satisfying various constraints including: minimum interwell spacing, maximum well length, angular limits for deviated completions, and minimum distance from reservoir and fluid boundaries. In the first stage, the wells are placed assuming that the wells can only be vertical. In the second stage, these vertical wells are examined for optimized horizontal and deviated completions. This solution is expedient, yet systematic, and it provides a good first-pass set of well locations and configurations. The first stage solution formulates the well placement problem as a binary integer programming (BIP) problem which uses a &ldquo;set-packing&rdquo; approach that exploits the problem structure, strengthens the optimization formulation, and reduces the problem size. Commercial software packages are readily available for solving BIP problems. The second stage sequentially considers the selected vertical completions to determine well trajectories that connect maximum reservoir pay values while honoring configuration constraints including: completion spacing constraints, angular deviation constraints, and maximum length constraints. The parameter to be optimized in both stages is a tortuosity-adjusted reservoir &ldquo;quality&rdquo;. The quality is preferably a static measure based on a proxy value such as porosity, net pay, permeabilty, permeability-thickness, or pore volume. These property volumes are generated by standard techniques of seismic data analysis and interpretation, geology and petrophysical interpretation and mapping, and well testing from existing wells. An algorithm is disclosed for calculating the tortuosity-adjusted quality values.

Determining optimal well locations from a 3D reservoir model

A method and apparatus are disclosed for recovering and separating diamondoid compounds from a produced natural gas stream containing dissolved diamondoids.

Method and apparatus for producing and separating diamondoid compounds

A process for recovering oil from fractured formations is provided which involves altering the wettability of the formation, particularly at the interface of the fracture and rock matrix. The process of the present invention improves the ability of injected fluids flowing in the fracture to enter the rock matrix to displace oil. When employed in conjunction with a water-wet fractured oil-bearing formation, the process comprises the steps of: injecting a wettability agent capable of transforming the water-wet fractured formation from water-wet to oil-wet; contacting the oil-wet fractured formation with the wettability agent so injected at a fracture/matrix interface; injecting an oil miscible solvent; and recovering oil. A process for use with an oil-wet fractured oil-bearing formation is also provided.

Oil recovery process for use in fractured reservoirs

A method and apparatus are provided for locating a solvent injection apparatus within a natural gas wellbore to reduce the deposition of hydrocarbonaceous solids which are at least partially soluble in the solvent.

Method and apparatus for locating solvent injection apparatus within a

A process is described to direct heat towards a productive interval of a reservoir during a thermal enhanced oil recovery (EOR) operation. A chemical composition suitable for producing a rigid polymer foam is injected above or below the productive interval. Once in place the temperature of the composition is increased and it reacts to produce a foamed polymer thermal barrier. The temperature can be increased by steam injection or in-situ combustion. After a rigid foam is formed, thermal efficiency is increased by reducing heat losses to non-producing zones during a thermal stimulation.

Thermal barriers for enhanced oil recovery

A liquid hydrocarbon and an insoluble displacing fluid are passed through a core sample from a subsurface formation. The two-phase effluent flow out of the core sample is collected in a container where the two phases separate into an overlying fluid phase and an underlying fluid phase and the volumes of each phase are measured as an indication of the permeability of the core sample. Such volumes are measured by placing fluid level detectors in the container and detecting the movements of the air-fluid interface of the top of the overlying fluid phase and the fluid-fluid interface between the two phases as the fluid is drained from the container.

Method and system for determining fluid volumes of a two-phase effluent

An enhanced oil recovery process in which carbon dioxide is injected into the oil-bearing formation under supercritical conditions to act as a solvent for the oil. Mobility of the carbon dioxide is controlled by the use of a dissolved polymer whose solubility is enhanced by the use of an entrainer comprising a polar organic compound such as an alcohol or a glycol.

Enhanced oil recovery using carbon dioxide

Method and system for measuring properties of fluids, particularly of reservoir fluids involved in enhanced oil recovery, comprising a pair of high pressure cells, each one of the cells having a floating piston therein which separates the respective cell into a fluid analysis chamber and a hydraulic fluid chamber. Means are provided for selectively controlling the amount of pressure applied to the hydraulic fluid chamber of each cell, whereby the pressure of the fluid under analysis is defined. Means are also provided for interconnecting the fluid analysis chambers of each cell whereby fluid under analysis may be selectively passed between the cells.

Method and system for measuring properties of fluids

A method for determining the CO.sub.2 minimum miscibility pressure (MMP) is disclosed which comprises filling a coiled capillary tube with oil at a predetermined temperature T.sub.1 and an initial predetermined pressure P.sub.1 less than the CO.sub.2 MMP. Carbon dioxide is injected into the capillary tube at a fixed flow rate F.sub.1 to displace the oil while maintaining the temperature of the oil at T.sub.1 and the pressure at P.sub.1. The pressure drop across the capillary tube and the volume of carbon dioxide injected is constantly measured. The pressure difference versus volume of carbon dioxide injected data is plotted and the pressure drop .DELTA.P.sub.1 at the point of inflection where the second derivative goes from a negative value to a positive value is determined graphically. The previous steps are repeated while maintaining T.sub.1 and F.sub.1 constant at a different pressure P.sub.2 less than the CO.sub.2 MMP and .DELTA.P.sub.2 at the inflection point of pressure versus volume of CO.sub.2 injected is determined. Additional CO.sub.2 displacement tests are conducted at the same temperature T.sub.1 and CO.sub.2 flow rate F.sub.1 at various pressure levels (at least two) above the CO.sub.2 MMP. The pressure drop at each pressure P.sub.3 and P.sub.4 above the CO.sub.2 MMP is plotted versus the volume of carbon dioxide injected. The pressure drop .DELTA.P.sub.3 and .DELTA.P.sub.4 at the point of inflection as previously defined is determined for the corresponding pressure P.sub.3 and P.sub.4. The corresponding pressure drop at the inflection point obtained for the pressure values below MMP and the pressure drop at the inflection point obtained for the pressure values above MMP minus the pressure drop for CO.sub.2 under the same test conditions as calculated by the Hagen-Poiseuille equation are plotted as a linear function of test pressure. The CO.sub.2 MMP is determined graphically as the pressure at the point where the two lines defining miscible and immiscible displacement intersect.

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Dallas, TX, United States of America

Alvin S Cullick