And this is to the top of the china wall on the block. May 1, 3. Ok got to thinking on this a little since my BBC block is not measurable currently. I measured 2 SBC intakes for the thickness from the base of the intake to the mounting pad for the distributor and that measurement is 1. The BBC intakes I measured the same thickness area and it was. So depending on the gap between the intake and china wall you would possibly have the BBC china wall a bit higher up than the small block by about.
I had one issue and it may be what you are having I do not know. If you drove it hard or even revved it to rpm it would jump time.. Like 70 degrees timing.
Long story short.. For some reason the combination was holding the distributor up too high. I machined the base where the gasket goes on one of the distributors i have laying around so it would sit deeper. I forget how much I took off but I think it was around. I got it to the point that it would bottom out when I stuck it into the intake hole and then I removed just a tick more so there was an air gap between the distributor and intake manifold..
The gasket held it up from bottoming out.. Issue solved. You only need to enter the cost values once and you can easily update these values at any time. Run multiple vertical or deviated cases at once. After the batch run completes, you can view a summary of your batch in an Excel spreadsheet.
Suite Fulshear, TX Request a Quote. Technical Support. Operators usually place the smaller-size rods at the bottom of the tapered rod string; the smaller sizes are able to handle the load there and reduce the overall string weight and load on the top sections.
Although continuous rod strings that are coupled only at the surface and at the downhole pump do exist, their use is limited. For the vast majority of rod-pumped wells, these strings are made up of a series of rods threaded at both ends and joined by couplings.
Because the outer diameter of the coupling is larger than that of the rod body, couplings routinely contact the tubing wall, particularly in deviated sections. Therefore, in addition to coupling strength and corrosion resistance, system designers take into consideration coupling hardness relative to the tubing to prevent tubing wear.
As an added precaution, designers may place heavier rods, or sinker bars, in the lower section of the rod string to keep the rod string in tension, which reduces buckling and may help prevent contact with the tubing wall.
Rod strings may also include stabilizer bars between sinker bars to centralize the rods, further reducing tubing wear. Rod guides , typically made of reinforced plastics, may be molded onto steel rods at depths where engineers predict the rods will experience side loading due to a deviated wellbore path. The guides act like bearings between the tubing wall and the rod to prevent rod and tubing wear.
Sliding guides are able to move between molded guides during the pump cycle, aid-ing production by scraping paraffin from the tubing wall, which helps pre-vent well plugging.
A rod rotator or tubing rotator may be used to rotate the rod a small fraction of a revolution on each stroke of the pumping unit to further extend rod string life. In addition, slow rotation of rod guides may help scrape paraffin from the tubing wall.
Sucker rods are connected to the surface pumping unit by a polished rod. The polished rod , made of standard alloy steel and hard-surface spray metal coating, supports the loads created during the pump cycle and ensures a seal through the stuffing box at the top of the well.
The stuffing box is attached to the wellhead or pumping tee and forms a low-pressure tight seal against the polished rod. The seal forms a barrier between the well and the atmosphere and allows flow to be diverted into the flowline via the pumping tee. The downhole pump is made up of a pump chamber, a plunger with a traveling valve and a standing valve; it is the mechanism by which fluid is moved up the tubing Figure 2.
A frequent challenge to downhole pump operation is the entry of gas into the pump, leading to fluid pound or gas interference. Fluid pound occurs when the plunger travels down quickly through low-pressure gas and then suddenly hits fluid; the resulting compressive shock can damage rod strings and the prime mover gearbox.
Gas interference is less damaging and occurs when the plunger travels down through high-pressure gas. Both conditions significantly reduce system efficiency.
To combat gas interference , gas separators are placed below the pump to redirect the gas into the wellbore annulus around the pump. Other modifications may be made to the completion to counter or reduce the effects of heavy oil and sand or other produced solids. Operators can diagnose gas interference, fluid pound severity and many other operating conditions using a dynamometer, which plots rod tension versus displacement measurements at the surface and downhole at the pump.
The shape of an ideal downhole graph, called a dynamometer card, is rectangular and indicative of a full pump. Deviations from the ideal shape indicate performance issues, such as gas interference, system leaks, stuck pumps, parted rods and many other anomalies that can be identified and corrected automatically or through manual intervention.
Two types of systems are available for improving pump efficiency and protecting the pumping system: pumpoff controllers and variable speed drives VSDs. When the dynamometer values indicate gas interference, pumpoff controllers can be programmed to turn off the surface unit for a set period, calculated to allow enough time for fluid to migrate through the reservoir and into the wellbore.
This method is less complex and less costly than using VSDs but it is effective only in areas where operators have sufficient production history to obtain accurate estimates of how long to shut down the unit. Based on dynamometer measurements, a VSD reduces the pump speed instead of turning the pump off.
This allows time for the pumps to become clear of gas or for liquid levels in the wellbore to rise without having to shut down. Use of VSDs is particularly effective in very-low-permeability formations and shales, where the time required for oil to migrate into the induced fractures and into the wellbore can be difficult to predict even across a single field.
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