In recent years, producers in the Eagle Ford Shale (EFS) shifted drilling focus from gas into more liquid areas, as prices have continued to favor oil over natural gas. The EFS is somewhat unique compared with the other unconventional shale areas, with a distinctive oil area dominated by light oil and condensate and increased Gas Liquid Ratios (GLR), which has become the targeted application for Hydraulic Jet Lift (HJL) systems. This paper aims to break some paradigms surrounding the misconception of the Hydraulic Jet Lift application selection. A large majority of producer companies rely on the technique of hydraulic fracturing or fracking, completion, crews pump proppant down hole at high pressures in order to fracture the well, and that pressure returns to the surface during the flowback period. Due to this production behavior, some producers consider HJL to produce the flowback, deploying it to establish operations and then converting to another form of lift for later production stages. For this stage the HJL design, it is performed using well simulation models based of multiphase flow correlation and basic jet pump principles. In the next production stage, one reason that HJL gets phased out, is related to the increased GLR of the produced fluids beyond the flowback period. However, as the GLR increases, it is required to bring together into the well model not only the expected production parameters but also key reservoir depth and API Gravity sensitivities; which helps to introduce the estimation of a GLR threshold limit. The introduction of this parameter widens the spectrum of the Hydraulic Jet Lift operation range in the EFS and can be expanded into other unconventional areas. This technique includes typical industry values to set the operation of the surface equipment to a maximum injection pressure of 4,500 psi and keeping horsepower below 300 HP. There are three relatively distinct "windows" in the EFS which reflects changes of type of fluids due to the distribution of initial GLRs, wells production generally correspond to the depth of the hydrocarbons being accessed and additionally GLR changes occurred as oil production declines. Since the most common casing and tubing size used across the EFS are 5-1/2" and 2-7/8", it causes and imminent flow restriction for gas flow within the HJL system. Targeting the "sweet spot" that involves lighter hydrocarbon fluids and an adequate GLR, has been proven to enhance the HJL selection across the EFS regional production windows. These results were derived from well modeling sensitivities; using wells within higher GLR areas and validated from US public production database, which has revealed the pump performance can be improved beyond the flowback production stage, thus extending the life of the ALS and avoiding unnecessary workovers. Even though HJL systems were originally conceived for wells with larger produced liquid volumes, it has been proven successful for lower liquid volume as described in this paper. As liquid production declines, it is important to note that gas/liquid volume distribution inside the pump will allow for higher gas volume. For this reason, when the produced liquids start to decrease, then the jet pump can handle progressively higher GLRs until the liquid economic limits is reached. For the well modeling using the casing/tubing sizes typically used within the EFS sweet spot area and based off industry completion standards; results have shown that for HJL to be effective the well's GLRs must be selected within a higher end threshold limit of around 2,000 scf/bbl. Lessons learned presented in this paper will help to further improve ALS operations by better understanding the HJL operation parameters and threshold limits. This will avoid an inadequate ALS selection thus loss in rate of return; due to the misconception of the HJL application selection in the unconventional areas where GLRs can be significantly higher. In a long-term perspective, the use of the HJL can be successfully extended from early to later production stage.

Plunger Lift systems (PLS) have been proven to be successful for decades in North America and extended into traditionally lower productivity well areas. As well production declines and the flowing bottomhole production increases, the velocity required to remove the accumulated liquids from the wellbore falls below critical velocity, therefore requiring the application of a deliquification method. This project aimed to study an unconventional well for plunger lift solution with challenging mechanical conditions and harsh downhole environment. In unconventional areas, selecting the proper Artificial Lift System (ALS) needed to produce huge gas reserves comes with technical challenges. A field case study is provided to review the selected horizontal well for a plunger lift solution with mechanical ID restriction in a currently ongoing full field development for an unconventional reservoir in Middle East. For the operating company, the original plan was to operate it with rod lift system. However, when the liquid production is not too large (<200 Bbl/d) and there is sufficient gas volume and pressure, plunger lift should be evaluated first, therefore postponing the rod lift installation. This paper will describe the process and results of installing a Tapered Progressive Plunger Lift (TPPL) solution in a horizontal with 5,000-ft lateral and downhole temperatures around 300°F. The existing completion design included a casing size reduced from 5-1/2″ to 4-1/2″ and subsequently designed with a reduced tubing string size as well, from 2-7/8″ to 2-3/8″, representing a mechanical restriction of the Internal Diameter (ID) profile. The tailored plunger lift solution was implemented allowing the packered well with a tapered tubing string design to unload liquids in the wellbore without having to pull the tubing. This was accomplished by adapting the PL installation with a tapered Intermediate landing assembly seating at the tubing crossover. This arrangement not only help counteracted the liquid accumulation of each tubing section but also extended the life of the well by minimizing the condensate to oil ratio and water to oil ratio. A secondary benefit was to fine tune the material selection of the downhole equipment for the harsh reservoir environment. The approach used to enable the adequate selection of the ALS will be described by detailing benefits and results of the TPPL application that have efficiently and economically added value to the unconventional well. In a long-term perspective, the implementation of the Tailored Plunger Lift Solutions can adapt successfully to other wells within the area where these types of completions are commonly use thus helping the full development of green unconventional fields.