Abstract: Disclosed are systems and methods of injecting steam into a wellbore. One disclosed injection tool includes a body defining an inner bore and a radial flow channel, one or more fluid conduits defined in the body at the radial flow channel, a shroud arranged about the body such that an annulus is defined and in fluid communication with the one or more fluid conduits and the surrounding wellbore environment, a sleeve arranged within inner bore and movable between a first position, where the sleeve occludes the one or more fluid conduits, and a second position, where the one or more fluid conduits are exposed, and first and second seals generated at opposing axial ends of the radial flow channel when the sleeve is in the first position.

Abstract: A control system for controlling the operation of a Downhole Steam Generator (DHSG) system includes a cascade control strategy for control of individual final control elements in communication with a local well master controller. The final control elements may control fuel, oxidant, feedwater, and/or carbon dioxide flow to the downhole steam generator. The local well master controller may monitor and adjust the flows to the DHSG to control the operating performance of the DHSG.

Abstract: A method for identifying fluid migration or inflow associated with a wellbore tubular, comprises measuring strain of the wellbore tubular with a system comprising at least one string of interconnected sensors that is arranged such that the sensors are distributed along a length and the circumference of the wellbore tubular; establishing a baseline that is a function of steady state strain measurements within a first time period; and identifying fluid migration or inflow where strain measurements substantially deviate from the baseline within a second time period.

Abstract: A system for estimating a wellbore parameter includes a first component located at or near a terranean surface; a second component at least partially disposed within a wellbore at or near a subterranean zone; and a controller communicably coupled to the first and second components. The second component is associated with a sensor. The controller is operable to: adjust a characteristic of an input fluid to the wellbore through a range of input values; receive, from the sensor, a plurality of output values of the input fluid that vary in response to the input values, the output values representative of a downhole condition; and estimate a wellbore parameter distinct from the downhole condition based on the measured output values.

Abstract: An improved hydrotest testing system comprises a safety stop which prevents the testing tools from being blown out of the top of the tubing string. The safety stop is made up into the upward facing box of the tubing joint to be tested, where the stop is positioned between the tool assembly placed within the tubing joint and the no-go head assembly which is located at the surface during the testing operation. Once the safety stop has been made up into upward facing box, the tool assembly is set within the joint to be tested and the joint pressure tested. The safety stop has a generally cylindrical body which has a bore extending through its length, where the bore has a reduced diameter throat which is sized smaller than portions of the downhole testing tool.

Abstract: A simple, applicable in the field, and extra-equipment free method is provided for determining steam dryness directly in a thermal recovery of high-viscosity oil. A non-condensable gas is added into a saturated steam being injected into a well. The presence of non-condensable gas changes partial steam pressure. Correspondingly the steam condensation temperature also changes. The borehole temperature or pressure measurements can be used to evaluate the steam dryness.

Abstract: A system for estimating a wellbore parameter includes a first component located at or near a terranean surface; a second component at least partially disposed within a wellbore at or near a subterranean zone, the second component associated with a sensor; and a controller communicably coupled to the first and second components operable to: adjust a characteristic of an input fluid to the wellbore through a range of input values; receive, from the sensor, a plurality of output values of the input fluid that vary in response to the input values, the output values representative of a downhole condition; and estimate a wellbore parameter distinct from the downhole condition based on the measured output values.

Abstract: The invention includes a method for determining a steam injection schedule for a set of subsurface formation subsurface regions of an oil field, the method including the steps of determining a thermal maturity for each subsurface region of the set; calculating a latent heat target for each subsurface region according to the determined thermal maturity therefore; calculating a steam injection target for each subsurface region according to the calculated latent heat target therefore; determining the availability of steam for injection to the subsurface regions; and calculating a steam injection schedule for each subsurface region according to the determined steam availability and calculated steam injection targets for all subsurface regions of the set.

Abstract: A modular steam injection line, for use in SAGD operations for delivery of an equal steam mass flow along a length of the apparatus, incorporates steam splitter modules fluidly connected for forming the steam injection line. Each of the modular steam splitters is fit with interchangeable nozzles for delivering steam to the formation. The interchangeable nozzles have orifices of different sizes and the nozzle orifice size required for each individual module to deliver an equal mass flow of steam from each module along the entire length of the steam injection line is calculated based on steam conditions at each module so that each module can be fit with nozzles having the appropriate sized orifices.