Existence of the water in a gas well may hinder the production of gas unless it is removed.  Therefore, unloading of the wells is one of the most important production challenges.  The unloading of the wells is especially challenging and not well understood for the horizontal portion of the well.  There are several factors affecting the flow.  Relatively low gas production rates make the water flow difficult and water may accumulate in the wells resulting in back pressure on the formation and in some instances the water goes back into the formation.  Horizontal wells can have an undulating trajectory resulting in low spots for water to accumulate and not be removed.  Moreover, the heel of the horizontal well could be at a shallower depth than the toe of the well.  This requires water to flow uphill in the well.  For the low gas rates typically produced from these horizontal wells, the water is inevitably expected to accumulate at the toe of the well.  There is no reliable model or software tool to predict the unloading of horizontal wells.  The tool development requires the accurate understanding of the hydrodynamic interplay between the gas and the water.

For oil dominated systems, there are unique operating issues that affect the decisions on the production operation and artificial lift method to be used.  Similar to gas dominated systems, the oil dominated systems require better characterization of the flow of various phases in the horizontal well.  Some of the specific issues are the determination of horizontal well trajectory, i.e., whether to drill the horizontal wells toe up or toe down, the existence of terrain induced slugging and its ramifications, placement of the artificial lift, scale formation, corrosion, foaming, asphaltene and paraffin deposition, frac-sand production.

Artificial lift techniques for horizontals are mostly based on practices established in vertical wells in offset fields, without acknowledging the fundamental differences.  Pros and cons of the various techniques in horizontals are not well established. Modeling tools are lacking to compare the performance of different techniques.

Moreover, there is no consensus within the petroleum industry as to drilling the wells toe-up or toe-down.  Various artificial lift scenarios have been envisioned by the industry which are listed as follows.

  1. Drilling sumps for placement of artificial lift equipment
  2. Placing artificial lift equipment in the horizontal sections of well
  3. Placing artificial lift equipment in the toes of horizontal wells.

The type of artificial lift system employed in a well affects the suitability for placement.  In addition, the well design (casing size, hole angle build rate, and dog-leg severity), as well as reservoir performance, will affect artificial lift choice and placement.  Current industry trends look to rod pumping, hydraulic pumping, progressing cavity pumping, electric submersible pumping, plunger lift, gas-lift, and foam as means for pumping or removing liquids from horizontal wells.  Each form of artificial lift has constraints or limitations associated with it.  These have been identified in the form of screening criteria for vertical or near-vertical wells.  Similar criteria must be developed for horizontal wells.  Placement of end-of-tubing, location for artificial lift (pump, gas lift), and casing size influence the scope and success of artificial lift.

The horizontal well trajectory (e.g. toe up, toe down) will impact the flow regimes occurring along the wellbore, the effectiveness and location of artificial lift equipment, and  ultimately  well capacity and ultimate recovery. The horizontal well trajectory is in many cases dictated by drilling location and reservoir architecture. Any compromise between the two needs to be struck early on in field development and requires clear qualification and quantification of the impact of trajectory on artificial lift success.  There exists scope for optimizing any trajectory e.g. by drilling a sump to locate artificial lift equipment.

Recommended practices for horizontal wells can be either experience-based or model-based. Model-based optimization starts with understanding the multiphase and transient flow phenomena that occur in horizontal wells.  The critical rate in horizontal wells differs from the critical rate in vertical wells and will impact, among other things, the onset of liquid loading.  Artificial lift techniques are intended to unload the liquids by changing the multiphase flow behavior.  Therefore, the flow behavior is a key to understanding and helping design the artificial lift techniques.

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