Fundamental aspects of pumping horizontal wells bellow the bubble-point pressure
Updated: Apr 26
Sucker-rod pumping brings a number of challenges when applied to horizontal wells:
A high hydrostatic pressure of liquids accumulated in the heel section
Multiple workovers replacing or repairing pumps due to excessive gas interference and solids deposited in the lateral
Poor pump efficiencies
A quick rise of gas-oil ratio (GOR) when the reservoir pressure drops below the bubble point of the oil
Normal ROT regarding well deviation:
from 0 to 3 degrees /100 ft - no problem
from 3 to 5 degrees/100 ft - increased wear and friction
>5 degrees/100 ft - increased operating costs, failures, gas interference, etc.
Increased wear, high operating costs, and pump failures are unavoidable even in horizontal wells with the long radius of heel section.
Phase distribution along the lateral of a multistage hydraulically fractured well
Several methods have been proposed and used in the industry to reduce the back pressure on the reservoir or the amount of free gas that enters the pump.
In this respect I would like to cite the following remark by Ann Muggeridge et al. (BP, E&P), "Recovery rates, enhanced oil recovery and technological limits,” Philos Trans A Math Phys Eng Sci. 2014 Jan 13:
During depletion, oil flows through the production wells to the surface because the pressure at the base of the well exceeds that exerted by the hydrostatic head of the column of oil in the well. Initially, this occurs naturally but over time the oil rate tends to decrease as the reservoir pressure decreases. In the absence of water injection, pumping may be used to maintain oil rate at economic levels.
If reservoir pressure falls below the oil bubble point pressure, gas that was initially dissolved in the oil will come out of solution and, because it has a much lower viscosity, will flow preferentially to the production well.
At the same time the viscosity of the remaining oil increases, reducing its mobility further. This will reduce the oil production rate further (although it may increase the total (oil plus gas) production rate through reducing the hydrostatic head in the well).
When we install a velocity string into the heel section of an oil well with a rod pump to implement one of the above mentioned methods, we may accelerate reservoir depletion and reduce EUR by abruptly lowering the bottomhole pressure.
I found many reports, in which the metrics of the success of an artificial lift system is the increase in the production rate achieved throughout a short period of time after its installation. Such an approach may be misleading since in tight oil reservoirs the transient flow period can be long. Additional parameters need to be considered are the decline rate of oil production and the rate of increase of GOR to determine properly the achieved improvement of well economics. In wells with a low productivity index, a significant decrease in the flowing bottomhole pressure over time may lead to a marginal increase in the oil production rate and a huge increase in the gas flow rate. The increase in the gas production rate can make the problem of flaring and venting of gas even worse, when the capacity of gas processing facilities is limited.
The recently introduced MAPS-AL multiphase advanced pumping system for artificial lift solves this challenge and helps operators improve well economics even at current commodities prices.
MAPS-AL transmits energy to the liquids located below the downhole equipment using a centrifugal pump at the surface. The system delivers liquid batches to the intake of the downhole pump to increase the pump fillage and prevents the formation of the stationary bed of solids in the production liner and heel section.
The latter feature is essential to avoid impaired productivity of perforation clusters within fracture stages and excessive solids concentrations in the fluids entering the downhole pump. MAPS-AL is engineered to lower gradually the flowing bottomohole pressure to maximize oil production and minimize the rate of increase of GOR.
Find out how here: Artificial Lift | Mpecorp
Reduce Lifting Cost
According to a survey conducted in the Permian Basin, the failure frequencies are as follows: total is 0.66 per well per year, pump is 0.25 per well per year, rod is 0.22 per well per year, and tubing is 0.16 per well per year. The failure rate was about 2.5 per well per year while pumping from the horizontal wells according to another study.
Since MAPS-AL enables oil producers to operate the rod pump in the vertical section and solve above challenges, on average, the potential savings in workover costs can be $100,000 per well per year at $50,000/workover.
After a well was drilled and produced for a period of time at high production rates, there are still substantial amounts of recoverable hydrocarbons in it, if lifting cost (the number of workovers to repair the pump/tubing) is not increased and the pump fillage is acceptable. Once the oil production rate is below 100 bpd, from 12 to 24 months after the initial production, the workover costs at a failure rate of 2.5 per well per year can become relatively large as compared to the generated revenue.
Production histories for the five main shale oil basins. Source EIA.
The well may produce 15-50 bpd for years strengthening the company's balance sheet if the lifting cost is under control. Therefore, this solution gives the opportunity for unconventional oil producers not to depend on the volatility in oil price, at least to the extent that we see today.