Showing papers on "Annulus (oil well) published in 2010"

Frictional Pressure Loss Estimation of Non-Newtonian Fluids in Realistic Annulus With Pipe Rotation

Abstract: The annular frictional performance of non-Newtonian fluids is among the major considerations during development of hydraulic programs for drilling operations Proper estimation of the frictional pressure losses become more critical when determining hydraulic horsepower requirements and selecting proper mud pump systems to foresee any serious problems that might occur with hydraulics during drilling operations Because the rheological behaviour of the non-Newtonian fluids is known to be challenging, it becomes even more complicated during pipe rotation, especially in eccentric wellbores In many cases, significant differences are observed when theoretical calculations and measurements for pressure losses are compared This study aims to develop correction factors for determining the frictional pressure losses accurately in eccentric horizontal annulus for non-Newtonian fluid, including the effect of pipe rotation Extensive experimental work has been conducted on METU-PETE Flow Loop for numerous non-Newtonian drilling fluids, including KCl-polymer muds and PAC systems for different flow rates and pipe rotation speeds, and frictional pressure losses are recorded during each test Rheological characteristics of the drilling fluids are determined using a rotational viscometer Observations showed that pipe rotation has a significant influence on frictional pressure loss, especially at lower flow rates Up to a point, as the pipe rotation increases, the frictional pressure losses also increase As the flow rates are increased, the effect of pipe rotation on frictional pressure losses diminishes Also, after a certain pipe rotation speed, no additional contribution of pipe rotation on frictional pressure loss is observed When the developed friction factors are used, there is a good agreement between the calculated and observed frictional pressure losses for any pipe rotation speed

Prediction of Ingress Through Turbine Rim Seals—Part I: Externally Induced Ingress

Abstract: Rotationally induced (RI) ingress is caused by the negative pressure (relative to the external air) inside the wheel-space of a gas turbine; this negative pressure, which is created by the rotating flow in the wheel-space, drives the ingestion of hot gas through the rim seals. Externally induced (EI) ingress is caused by the circumferential distribution of pressure created by the blades and vanes in the turbine annulus: Ingress occurs in those regions where the external pressure is higher than that in the wheel-space, and egress occurs where it is lower. Although EI ingress is the dominant mechanism for hot-gas ingestion in engines, there are some conditions in which RI ingress has an influence: This is referred to as combined ingress (CI). In Part I of this two-part paper, values of the sealing effectiveness (obtained using the incompressible orifice equations developed for EI ingress in an earlier paper) are compared with published experimental data and with the results obtained using 3D steady compressible computational fluid dynamics (CFD). Acceptable limits of the incompressible-flow assumption are quantified for the orifice model; For the CFD, even though the Mach number in the annulus reaches approximately 0.65, it is shown that the incompressible orifice equations are still valid. The results confirm that EI ingress is caused predominantly by the magnitude of the peak-to-trough circumferential difference of pressure in the annulus; the shape of the pressure distribution is of secondary importance for the prediction of ingress. A simple equation, derived from the orifice model, provides a very good correlation of the computed values of effectiveness. Using this correlation, it is possible to estimate the minimum sealing flow rate to prevent ingress without the need to know anything about the pressure distribution in the annulus; this makes the orifice model a powerful tool for rim-seal design.

Wellbore treatment apparatus and method

Abstract: A method for wellbore treatment includes running a liner into a wellbore, the liner including a wall, an inner bore defined by the wall, a first port through the wall, a second port though the wall spaced axially from the first port, a first removable closure for the first port and a second removable closure for the second port; positioning the liner in an open hole section of the wellbore to create an annulus between the liner and a portion of the wellbore wall and with the second port downhole of the first port; inserting a treatment string assembly into the liner, the treatment string assembly including a tubing string and an annular seal about the tubing string and being insertable into the inner bore of the liner; setting the annular seal to create a seal between the tubing string and the liner downhole of the second port; and while the first port is closed to fluid flow therethrough, pumping wellbore treatment fluid into an annular area between the tubing string and the liner such that the fluid passes through the second port and into the annulus to treat the open hole section of the wellbore adjacent the second port. The treatment string assembly may further include a port-opening tool and a fluid communication port permitting fluid communication between the tubing string outer surface and a fluid conduit through the tubing string adjacent an upper side of the annular seal.

Theory of breakup of core fluids surrounded by a wetting annulus in sinusoidally constricted capillary channels

Abstract: Analysis of core-annular dynamics in the presence of base flow for arbitrary fluid viscosities leads to an equation describing the temporal evolution of the fluid/fluid interface. The equation follows from the conservation of mass in the “small-slope” approximation. Its useful applications occur, for example, in chemical engineering and petroleum recovery. The nonlinear equation allows inexpensive numerical analysis. For sinusoidally constricted pores, a purely geometric criterion exists that enables or prohibits the core-fluid breakup in the necks of the constrictions. The geometrically favoring condition sets up capillary-pressure gradients that ensure a continuous outflow of the core fluid from the necks into the “crests” of the profile. Such behavior is indeed observed in the numerical solutions of the evolution equation. For relatively large slopes of the initial configuration, setting up larger pressure gradients, the interface shape remains “smooth,” the evolution times are relatively fast, and the breakup is typically achieved by the growing film-fluid collar touching the axis of the channel at a single point. No satellite droplets are produced. Decreasing the slope lengthens the evolution times, allowing the formation and growth of “wavy” disturbances on the initial interface profile, which may touch the axis of the capillary in several places forming satellite drops. Thinner initial annuli also slow down the evolution process. Instability develops for the cases of the core both more and less viscous than the film. Finally, if the geometry prohibits the snap-off altogether, the initial interface configurations decay into steady-state solutions, and no breakup takes place. The solutions of the evolution equation validate well against two computational-fluid-dynamics codes.

Apparatus and method for downhole steam generation and enhanced oil recovery

Abstract: A burner with a casing seal is used to create a combustion cavity at a temperature sufficient to reservoir sand. The burner creates and sustains hot combustion gases at a steady state for flowing into and permeating through a target zone. The casing seal isolates the combustion cavity from the cased wellbore and forms a sealed casing annulus between the cased wellbore and the burner. Water is injected into the target zone, above the combustion cavity, through the sealed casing annulus. The injected water permeates laterally and cools the reservoir adjacent the wellbore, and the wellbore from the heat of the hot combustion gases. The hot combustion gases and the water in the reservoir interact to form a drive front in a hydrocarbon reservoir.

Downhole vibration apparatus and method

Abstract: A method of extending an earthen bore comprises the steps of rotating a drill bit at the end of a tubular while vibrating the tubular. The method results in reduced friction to tubular advance through the bore and results in stabilized drill bit loading and longer usable drill bit life. A method of conditioning a cement slurry in an annulus between a casing and a bore to improve a resulting cement liner comprises the steps of coupling a vibration generator to the casing, running the casing into the bore, displacing the cement slurry into the annulus and using the vibration generator to vibrate the casing. A vibration generator may comprise a mass, having a mass center, coupled to a frame, a motor and a power source to spin the mass about an axis offset from the mass center.

Hole Cleaning Performance of Light-Weight Drilling Fluids During Horizontal Underbalanced Drilling

Abstract: Hole cleaning is a major consideration at both the design and application stages of a drilling operation. If the fluid velocity is lower than a critical value at horizontal or high inclinations, a stationary bed develops which may cause various problems, such as high drag, higher probability of stuck pipe and higher hydraulic requirements, etc., if not removed properly. Therefore, this becomes important and essential to identifying critical velocity. This study aims to estimate the critical fluid-flow velocity for preventing the development of a stationary bed using empirical correlations that can be used easily at the field. Also, a rough estimation of bed thickness is introduced if the flow velocity is lower than the critical velocity. For this purpose, extensive cuttings transport experiments with water, called the Cuttings Transport Flow Loop, were conducted by the Petroleum and Natural Gas Engineering Department at Middle East Technical University (METU) in order to determine various inclinations, flow rates and rate of penetrations. The inner pipe is subject to a sagging, therefore more realistic annulus representation is achieved. Observations showed that a stationary bed can be developed even when the inclination of the wellbore is down to 50°. Results showed that the critical velocity could be estimated using the proposed correlations with reasonable accuracy when compared with the experimental results. Also, for flow velocities less than the critical values, the thickness of the stationary bed can be detected mostly within an error range of ±15%.

Modeling of Sand Cleanout With Foam Fluid for Vertical Well

Abstract: SummaryFoam has proved to be effective and economical in underbalanced operations and is gaining wider applications in many areas. Foam fluid has low density and high blocking ability. It can effectively reduce leaking of fluid into formation in low-pressure wells, protect-ing the oil formation and improving sand-cleanout efficiency. Accord-ing to energy-conservation equations, mass-conservation equations, and momentum-conservation equations, a mathematical model for sand cleanout with foam fluid was established that considers the heat transfer between foam in the annulus and foam in the tubing. The model was solved by numerical method. Distributions of foam temperature, foam density, foam quality, pressure, and foam velocity in the wellbore were obtained. Calculation results show that tempera-ture distribution is affected greatly by thermal gradient. As the well depth increases, foam pressure and foam density increase and foam quality and velocity decrease. Foam velocity at the well bottomhole is the minimum. Friction pressure loss of foam is less than that of water at the same volume flow rate. Site applications show that sand cleanout with foam fluid can prevent fluid leakage effectively. It can avoid damage of sealing agents and reduce pollution. The average relative error and standard deviation between model and field data on injection pressure are −0.43 and 2.55%, respectively, which proves the validation of the mathematical model.IntroductionCuttings, sands, or fines left in the wellbore can have a nega-tive effect on well completion and production because of flow restriction to the produced gas and oil. Hence, sand cleanout has been a standard practice in oilfield operations. Several techniques (Heinrichs and Dedora 1995), such as dual string system, pump to surface bailing, and coiled tubing with jetting, have been developed over the past decades. One of the most common cleanout opera-tions is running in with coiled tubing and circulating out the fills with carrying fluids. Because produced fluid usually is more than injected fluid, the bottomhole pressure (BHP) of many oil wells is very low. Therefore, sand cleanout using water or brine has only limited application because of leaking. Stable foams have been used as circulating fluids in drilling and workover operations since the late 1960s. Successful applications have been well documented in foam drilling operations (Hall and Roberts 1984; Fraser and Moore 1987; Falk and McDonald 1995; Lage et al. 1996). Research has been done on the behavior of stable foams (Doane et al. 1996; Meng et al. 1996; Negrao and Lage 1997; Nakagawa et al. 1999). Recently, stable foams have been used for underbalanced drilling both in vertical and in inclined holes. In many cases, drilling with foam has shown to provide significant benefits, including increased productivity (by reducing formation damage), increased drilling rate, reduced operational difficulties associated with drilling in low-pressure reservoirs (e.g., lost circulation and differentially stuck pipe), and improved formation evaluation while drilling.Foam generally is formed by mixing a gas phase with a liquid phase, which is either water (stable foam) or aqueous polymer solution (stiff foam) containing from 0.5 to 1% by volume foam-ing agent. The foaming agent usually is surfactant that can reduce surface tension between gas and liquid. The major advantage of foam is its flexibility in controlling the density in wellbore, which influences the BHP strongly. Characteristically, the foam viscosity is much greater than that of the liquid and gas phases. High viscos-ity can improve cuttings transport and sand-carrying ability. Usu-ally, foam flow in the wellbore keeps laminar flow, which results in lower pressure losses. Foam also has the ability to temporarily block a high-permeability layer, which can reduce fluid leaking into the oil formation.Because foam is a compressible fluid, special care needs to be taken in hydraulics calculations. This is mainly because of (1) inadequate foam rheology models and (2) influence of frictional and hydrostatic pressure components through the pressure-depend-ent fluid density. A number of rheology models have been developed for foam hydraulics calculations in the past 3 decades. These models include those by Beyer et al. (1972), Blauer et al. (1974), Sanghani (1982), and Phillips et al. (1987). Ozbayoglu et al. (2000) conducted a com-parative study of these models. They also measured foam pressure drops across a 90-ft horizontal pipe. On the basis of the comparison of experimental data and the results of the models, they concluded that there is no best model for predicting the pressure losses during foam flow in pipes under the experimental conditions. Models that may predict pressure losses closer to actual values in one case may not be suitable for another condition. Their experimental data indi-cate that foam rheology can be characterized better by the power-law model for 0.70 and 0.80 foam qualities, whereas the Bingham plastic model gives a better fit for 0.90 foam quality. Guo et al. (1995) presented a trial-and-error method to couple the frictional and hydrostatic pressure components through the pressure-dependent fluid density. Their technique gives results similar to that given by the computer models of Anderson (1984) and Okpobiri and Ikoku (1986). Both steady-state-flow and tran-sient-flow simulators are available in the drilling industry for foam drilling hydraulics calculations. During sand-cleanout operations using foam fluid, predicting such parameters as BHP, foam flow velocity, foam density, and foam quality in wellbore is a major challenge. Unlike incompress-ible fluids, foam is a compressible, high-viscosity, non-Newtonian fluid. Temperature, pressure, foam quality, foam density, flow velocity, and rheological parameters vary along the wellbore; in addition, frictional pressure gradient, hydrostatic pressure gradi-ent, and acceleration pressure gradient are coupled. This becomes more complex when polymer is added to the liquid phase (Chen et al. 2009). Unfortunately, the results from these simulators are frequently conflicting (Griffin and Lyons 1999; Nakagawa et al. 1999) because of assumptions that were made in mathematical formula-tions and rheological modeling. Many factors, such as operation conditions (flow rate, flow regime penetration rate), well configu-ration (deviation angle, hole size, pipe size, structure), foam fluid properties (rheology, friction, density, fluid loss), and the proper-ties of carried particles (shape, size and size distribution, density) can affect wellbore-cleanout efficiency.In order to improve the accuracy of pressure predictions in foam cleanout, we have developed a closed mathematical model to fully couple the temperature, frictional, and hydrostatic pressure compo-nents in this study. The newly developed model, together with the rheological model, was validated to design proper volumetric flow rates of gas and liquid phases, injection pressure of the wellhead, and foam temperature and density in the wellbore.

Control method and apparatus for well operations

Abstract: A method of controlling the annular pressure in a well during a well construction operation The operation comprises pumping a fluid down a tubing located within the well and extracting the fluid that flows back through an annulus within said well and surrounding the tubing The method comprises defining a set pressure pref, determining a desired extraction flow rate qc of fluid from said annulus in dependence upon the set pressure pref and a pumped flow rate into the annulus, and configuring an extraction path to achieve said desired extraction flow rate

Shock absorber having unidirectional fluid flow

Abstract: A twin-tube shock absorber comprising an outer tube which houses an inner tube. The inner tube forms an annulus area between the outer tube and the inner tube, and includes a check valve for allowing a fluid to flow unidirectionally from the annulus area to the interior volume of the inner tube. The shock absorber includes a piston which is slidably disposed within the inner tube and divides the interior volume into a rod side chamber and a cap side chamber. The piston includes a check valve allowing the fluid to flow unidirectionally from the cap side chamber to the rod side chamber. A flow regulator is disposed about the inner tube for allowing the unidirectional flow of fluid from the rod side chamber to the annulus area, wherein the flow regulator provides a resistance against the flow of the fluid from the rod side chamber to the annulus area.

An Examination of the Influence of Strain Rate on Subfailure Mechanical Properties of the Annulus Fibrosus

Abstract: Disk herniation is often considered a cumulative injury in that repetitive stress on the posterior annulus can result in the nucleus pulposus penetrating the annulus fibrosus and eventually extruding posteriorly. Further, it has been documented that the nucleus pulposus works its way through the annulus through clefts, which form as a result of repetitive tensile strain. The annulus fibrosus is viscoelastic in nature and therefore could express different mechanical responses to applied strain at varying rates. Other viscoelastic tissues, including tendons and ligaments, have shown altered mechanical responses to different rates of applied strain, but the response of the annulus to varying rates of strain is largely unknown. The present study examined the mechanical properties of 20 two-layered samples of porcine annulus fibrosus tissue at three distinct rates of applied 20% biaxial strain (20% strain over 20 s (slow), over 10 s (medium), and over 5 s (fast)); these three rates are considered applicable to nontraumatic loading. No differences in the stiffness or maximum stress in each of the two directions of applied strain were observed between the three strain rates. Specifically, the average (standard deviation) moduli calculated at the fast, medium, and slow rates, respectively, in the axial direction were 7.42 MPa (6.06), 7.77 MPa (6.61), and 7.63 MPa (6.67) and 8.22 MPa (8.4), 8.63 MPa (9.00), and 8.49 MPa (8.69) in the circumferential direction. The maximum stress values reached during the fast, medium, and slow rates, respectively, in the axial direction were 0.40 (0.36) MPa, 0.40 (0.36) MPa, and 0.39 (0.35) MPa and 0.45 (0.47) MPa, 0.44 (0.46) MPa, and 0.43 (0.46) MPa in the circumferential direction. At submaximal strain magnitudes over a range of nontraumatic rates likely to result in clefts in the annulus and potentially leading to disk herniation, any strain rate dependence is not significant.

Apparatus and method for detecting and quantifying leakage in a pipe

Abstract: The present invention relates to a method and an apparatus to investigate and quantify a leakage rate for a fluid (FG, FL) between a first pipe (5) and a second pipe (7), the first pipe (5) being surrounded by at least a portion of the second pipe (7), where the pipes (5, 7) are arranged in a well (1) in a ground and where a measuring arrangement (20) including a flow meter (24) and a pressure meter (26) is put into fluid communication with an annulus (B) defined by the first pipe (5) and the second pipe (7), where fluid (FG) in the gaseous phase is conveyed through the measuring arrangement, as the annulus (B) is used as a separation chamber for gas (FG) and liquid (FL).

Tubing hanger running tool with integrated landing features

Abstract: A system, in certain embodiments, includes a tubing hanger running tool (THRT) configured to position a tubing hanger within a wellhead. The THRT includes an integrated pressure equalization system including a tube having a first end in fluid communication with an annulus of the wellhead, and a second end in fluid communication with a control line. The integrated pressure equalization system also includes a piston disposed within the tube. The piston is configured to move within the tube to balance a pressure differential between a first fluid within the annulus and a second fluid within the control line.

Device for rock debris annulus re-injection

Abstract: The utility model discloses a device for rock debris annulus re-injection, which selects a water injection well to be a re-injection well, an internal annulus (9) is formed between a water injection pipeline (7) of the middle and a 9-5/8''casting (8), and an external annulus (11) is formed between the 9-5/8'' casting (8) and a 13-3/8''casting (8). The utility model is characterized in that a water injection pipeline isolating valve (2), a pressure control valve (3), an internal annulus isolating valve (4), an internal annulus pressure gauge (5) are arranged between an extension pipe (1) of the water injection pipeline (7) and a discharge pipeline (6) of the internal annulus (9) for the rock debris annulus re-injection operation technology of the offshore oil drilling; when the external annulus (11) arranged formed between the 9-5/8''casting (8) and the 13-3/8''casting (8) carries out rock debris re-injection, an adjustment pressure valve allows the discharge pressure to pressurize the internal annulus so as to prevent the rock debris re-injection size from flowing the internal annulus, the space of the internal annulus can be protected and the completeness of the water injection well can be protected.

Gas Lift Well Surveillance

Abstract: Apparatuses, methods, and computer program products for evaluating the performance of a gas lift well are disclosed. A gas lift well surveillance kit is disclosed. A method for evaluating the performance of a gas lift well includes injecting a tracer into an annulus, measuring a concentration of the tracer present in a substance retrieved from the well, determining actual travel times of the tracer, segmenting the gas lift well into a plurality of ranges of well depth, determining lift gas loss parameters, calculating lift gas velocities in the annulus and in the production tubing for each of the plurality of ranges of well depth based on the lift gas loss parameters, and determining points of entry of the lift gas into the production tubing based on: (i) the actual travel times of the tracer, and (ii) the lift gas velocities in the annulus and in the production tubing.

Mechanism of annular fluid thermal expansion pressure in HTHP sour gas wells

Abstract: In HTHP sour gas wells,over-high pressure in annulus will affect normal productionOnce it exceeds the allowable limit,potential safety hazards will be evokedIn view of high pressure problem resulting from thermal expansion of annulus fluid due to the temperature increase during the production period,a calculation model was established for that pressure in HTHP sour gas wellsAnd case studies were then madeThe results show that the heat-induced annulus pressure can cause failure in production pipe string,posing threat to safe productionSo when doing casing program planning,casing strength designing,and optimal annulus fluid determining,we had better to reduce the production-heat-induced annulus pressure and to manage the annulus pressure effectively while maintaining normal operation system,so as to ensure long-term safe production in HTHP sour gas wells

Pump in reverse outliner drilling system

Abstract: A liner string for a well has a liner hanger assembly at an upper portion of the liner string. A profile sub is located at a bottom portion of the liner string. A bottom hole assembly is latched to the profile sub. The operator lowers the liner string into the well with a drill pipe string and rotates the drill pipe string to rotate the drill bit to deepen the well. At a selected depth, the operator releases the bottom hole assembly from the profile sub and reverse circulates drilling fluid from a liner annulus surrounding the liner string, pumping the bottom hole assembly up the liner string. When the bottom hole assembly reaches the lower end of the drill pipe string, it latches to a catcher tool located at the lower end of the drill pipe string. The operator moves the liner hanger assembly into setting engagement with the casing string, releases the drill pipe string from the liner string, and retrieves the drill pipe string along with the bottom hole assembly.

Method and apparatus for separating downhole hydrocarbons from water

Abstract: The invention provides a method and apparatus for the downhole separation of a gas/oil/water fluid mixture and the injection of the separated water component into the formation containing the borehole. The fluid mixture is delivered into the wellbore through perforations in a casing at a production zone and delivered through check valves in a tubing string into an annulus between the casing and the tubing string. Hydrocarbons are returned to the production tubing and flow to the surface under formation or pump pressure and water is discharged from the annulus into an injection level isolated from the production zone.

System for analysing gas from strata being drilled under high mud flows

Abstract: A gas analysis system for determining the gas content of subterranean strata. A boring operation is commenced to form a borehole into or through a subterranean formation, such as a coal or shale formation to determine the gas content thereof. The drill fluid, cuttings and any desorbed gas is carried from the downhole location to surface analysing equipment in a closed system, so that the desorbed gases are not exposed to the air. The drill stem is capped or sealed at the surface, as well as the wellbore annulus to effectively seal the drill liquid, cuttings and desorbed gasses. The drill fluid, cuttings and desorbed gasses from the formation are coupled from the wellhead apparatus to the gas processing equipment via a closed system so that the constituents and volume of the gas can be determined.

Method and apparatus for freeze-thaw well stimulation using orificed refrigeration tubing

Abstract: A method and apparatus for introducing refrigerant into a wellbore, for freeze-fracturing a selected region of a subsurface formation, uses refrigerant diffuser pipe having multiple orifices in a selected pattern along a designated section of its length. The orificed supply tubing is disposed within a refrigerant return conduit, thereby forming a tubing annulus. A flow of liquid refrigerant is introduced into the diffuser pipe and flows through the orifices into the tubing annulus, with the orifices acting as expander means creating a pressure drop and causing vaporization of the refrigerant as it passes into the annulus. To facilitate use of the same diffuser pipe in different wells having different requirements, a helical orifice-isolation wrap may be disposed around the diffuser pipe, with the orifice-isolation wrap having orifice-plugging elements arrayed to effectively block fluid flow through selected orifices, while leaving other orifices open as required. In this way, it is possible to design diffuser pipes with particular orifice arrangements that will accommodate two or more different isolation wraps, with each different wrap plugging different patterns of orifices.

Systems and methods for deliquifying a commingled well using natural well pressure

Abstract: A method for removing fluids from a commingled well comprises positioning a fluid removal system in the well. In addition, the method comprises sealing a first formation from a second formation, shutting in the annulus, and closing off an inner flow passage of a tubing string. Further, the method comprises allowing the pressure of the first and second production zones to build up naturally. Still further, the method comprises flowing a fluid from the first production zone through a first of a plurality of check valves into the inner flow passage, and flowing a fluid from the second production zone through a second of the plurality of check valves into the inner flow passage. Moreover, the method comprises re-opening the inner flow passage of the tubing string and lifting the fluid in the inner flow passage to the surface.

System and method for intermittent gas lift

Abstract: A gas-lift apparatus and method for use in a well in which liquids accumulate in a liquid zone. The apparatus comprises a first string extending into the liquid zone and having upper and lower ends; a second string surrounding the first string and defining an annulus therewith, the second string extending a distance from the first string lower end such that the annulus has upper and lower ends, the annulus being closed at its upper and lower ends and defining a chamber, the chamber being in fluid communication with the inside of the first string; a check valve controlling the flow of liquid into from the wellbore into the lower end of said annulus; a gas valve allowing the flow of gas from the first string into the upper end of the chamber; and a valve for controlling the flow of gas into the upper end of said inner string.

Systems and methods for monitoring cement quality in a well

Abstract: A method for analyzing cement in a well annulus, comprises measuring strain of a casing in the well 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 casing; after pumping cement into the well annulus: establishing a baseline that is a function of steady state strain measurements within a first time period; and identifying strain measurements that substantially deviate from the baseline during a second time period.

Double string pump for hydrocarbon wells

Abstract: A double string pump transports liquids to the surface of a hydrocarbon well including a hydrocarbon well that is producing both natural gas and liquid fluids. The double string pump includes a hollow tube that raises and lowers the plunger and carries the liquids to the surface and an outer tube receives liquids down into the well to lubricate the moving parts and flush particles from areas prone to wear and back toward the production tube. The natural gas is produced through the annulus between wellbore casing and the outer production tubing string.