WHOC 2015 Presentation

The intention of this presentation is to provide you with an immediately actionable process that will improve your company’s profitability.

CHOPS is the acronym for Cold Heavy Oil Production with Sand, a non-thermal recovery technique used in unconsolidated sandstone reservoirs. Inducing sand inflow has increased production rate by an order of magnitude and doubled recovery.

To date, CHOPS has been used only in vertical wells. Sequential CHOPS re-completions in horizontal wells from Toe to Heel spaced so that the resulting produced areas overlap could result in multiples of vertical well recovery at a capital cost per recovered barrel competitive with current practices.

CHOPS began when the progressing cavity pump overcame rod float making it possible to achieve maximum drawdown. At maximum drawdown disintegration of the near wellbore matrix and other formation alterations take place that increase rate and recovery.

Insular depleted areas form around a well when draining fluids from unconsolidated sandstone. This leaves up to 90% of the reservoir unaffected by production.

Horizontal wells in unconsolidated sandstone are designed to prevent sand inflow while obtaining production from long continuous sections of reservoir. Preventing sand inflow obstructs ultimate recovery. The long wellbore produces high rates that payout drilling and completion in an acceptable amount of time, but horizontal wells have been economic failures as they cost twice as much to drill and complete as a vertical CHOPS well for similar recovery. Horizontal well CHOPS can change this.

3D seismic delineated the drained areas surrounding CHOPS wells and showed large expanses of reservoir between wells were unaffected by production. Bottom hole pressure in a depleted well is less than 1% of original pressure and will remain so for years. Infill drilling outside the depleted areas encounters original reservoir pressure. These factors suggest the occurrence of phenomena in the reservoir that establishes pressure discontinuity between depleted areas.

The size of the seismic depleted area is similar to that of a drained area calculated from the volume of recovered fluids and sand. The diameter of the drained areas ranged between 100m and 300m. Applying volumetric calculation along a horizontal wellbore results in a drained area width up to two orders of magnitude less that the diameter of a CHOPS well.

It follows from these observations that Horizontal Well CHOPS would increase recovery in two ways:

Inducing sand inflow would widen the drained area along a horizontal wellbore up to two orders of magnitude.
Spacing sequential CHOPS re-completions from the Toe to Heel of the well would be similar to an equivalent number of vertical CHOPS wells placed close enough together that their depletion areas meet or overlap.

In the second phase of a new pool development, this horizontal well was drilled parallel to two depleted vertical wells in 4m of net pay. The vertical wells were 400m apart and the horizontal well was 190m from the vertical wells.

Three slot sizes were positioned between inflatable external casing packers to evaluate productivity and sand control.

First, the Toe was isolated and produced to economic depletion. The isolation tools were then removed so that the entire liner could be produced. No change in production rate indicated no inflow from the other slot sizes.

Next, the Mid-Liner was perforated over a continuous 50m interval.

After the Mid-Liner perforations reached economic depletion the liner was perforated a second time. The second set of perforations consisted of 40m in the Heel, 20m in Mid-Liner 15m uphole from the first set, and 40m in the Toe.

The PCP was landed at the top of the build section at all times. Sand was encountered in the liner from the first set of perforations but only a trace of sand reached surface at anytime the well was on production.

Each time the well reached economic depletion perforating the liner generated incremental oil recovery.

The first perforation event was placed in a section of the liner approximately half way between the depleted areas of the off-setting vertical wells. Recovery was 70% of the average from the off-setting vertical wells.

The second perforation event is less informative in terms of the source of inflow due to perforations being made in the heel, mid-liner, and toe. Still, it successfully restored production and recovered 129% of the average from the off-setting vertical wells.

Of the 576 horizontal wells studied in this region, this was the only one found to be perforated after initial economic depletion. Also, it was the only horizontal well that recovered multiples of the volume of off-setting vertical wells.ur own text

Horizontal wells in this area abruptly loose inflow much like the vertical CHOPS wells do. Early on it was believed that fill had entered and plugged the liners. Liner clean-outs at economic depletion recovered very little fill and did not improve inflow. These experiences led to the practice of suspending a horizontal well when it reached economic depletion.

The fact that incremental recovery was obtained twice through perforating after the case study well had reached economic depletion suggests that there are several hundred wells in this region that could at least double recovery by sequentially perforating the liner.

Comparing the widths of depleted areas emphasizes the extent that recovery could be increased by perforating the liner to restore inflow.

To ensure optimum fluid production in vertical CHOPS wells, the bottom of the pump is landed below the perforations to keep the perforations clear of sand. The PCP in this well had to be landed hundreds of meters from the perforations to avoid rapid rod and/or tubing failure. Trace amounts of sand at surface indicated that the bulk of the sand flowing into the liner could not be transported such a long distance to reach the pump intake.

Conventional oil horizontal well producers report that re-completion of liners by perforating to allow for controlled intermittent production of solids for brief periods stimulates inflow that had been declining. The paradigm shift from doing all that was possible to prevent sand inflow, to doing all that is possible to maximize sand inflow occurred in cold heavy oil with the introduction of the PCP. These two situations exemplify that when the benefits of inducing sand inflow become apparent, engineered solutions for producing, handling, and disposing of produced sand become part of the daily operations.

Knowing CHOPS has a finite diameter depleted area, re-completions would have to be sequenced from Toe to Heel to tap all of the reservoir along the length of the well.

Effective sand removal at the perforations is critical for CHOPS recovery. Attempts to keep long perforation intervals open would require multiple expensive workovers and production tubing would likely get stuck in the liner. Very short lengths of perforations could be kept virtually sand free using common operating practices.

With no downhole moving parts, effective operation at any angle, ability to pass through the build section without damage, no rod string, no electric cable, relatively small diameter, short length, low risk of destruction when pumped off, and the ability to produce high solid content fluids and viscous fluids are attributes that make the jet pump more suited to this application than other pump systems. Although it has a reputation for lower efficiency and greater energy consumption than other pump systems, it is the pump for this job.

A section of land in Tangleflags having both vertical and horizontal wells in the Lloydminster zone provided the production profiles used to generate a capital cost estimate per recovered barrel.

This is the least prolific zone in the region but it is contiguous over many square miles. Thousands of wellbores have produced from this zone making it a reliable source for developing a capital cost estimate for a low quality reservoir. If horizontal well CHOPS can be shown to be profitable in this reservoir, it would be more profitable in reservoirs with better pay.

The vertical wells had been drilled and produced to depletion about 20 years before the horizontal wells were drilled. The averaged recovery from these wells is used as the expected recovery per sequenced re-completion in horizontal well CHOPS.

Although the average drained area diameter of the vertical wells is 90m, pragmatism suggests using a 100m drained area diameter for the ultimate recovery estimate from sequential re-completions.

This region has multiple pay zones. Typically a vertical well is not drilled with the Lloydminster being the sole target because the recovery is too low for an attractive capital cost per recovered barrel.

The CAPEX for vertical wells targeting only the Lloydminster provides insight into the relative profitability of exploiting this large asset using vertical wells or horizontal wells. Further, it would require 224 vertical wells to access the same amount of reservoir as the 14 horizontal wells.

Recovery from horizontal well CHOPS depends on how much of the wellbore is in effective pay. Effective pay is determined by reservoir heterogeneity and planar unevenness. A 1,500m wellbore can have 16 re-completion sequences spaced at 100m intervals. If each re-completion sequence produced the average volume of oil derived from the vertical off-setting wells, this is deemed as 100% of the wellbore being in effective pay.

The CAPEX presented for re-completing existing horizontal wells, and for drilling parallel horizontal wells, represents 100% to 50% of the wellbore being in effective pay.

Generally, thicker pay would result in wider well spacing and re-completion spacing. Combined with more oil recovery per meter of wellbore, thicker pay would require less capital per recovered barrel.

Pad drilling is known to reduce drilling costs.

Adding horizontal well CHOPS to pad drilling provides these other capital cost reduction opportunities:

Pad drilling 14 parallel horizontal wells requires 60% less surface land than 16 wells on 40 acre spacing.
Wellhead proximity and longer well life promotes infrastructure savings in flowlines, solution gas gathering, central treating facilities, sand disposal, oil sales, SCADA control and monitoring, and electrification.
Follow up flood schemes would not require infill drilling nor extensive additional flowlines.

CHOPS occurs when maximum drawdown is applied to unconsolidated sandstone.

At maximum drawdown, an active water aquifer or gas cap breaks through in a few months. The characteristics and behavior of unconsolidated sandstone makes reversal virtually impossible resulting in lost reserves.

3D seismic over depleted vertical wells can help identify where to place wells to avoid the depleted areas when infill drilling. In addition, techniques have been developed to successfully drill horizontal wells between depleted vertical wells.

Vertical well flood schemes recover 8% to 12% due to the rapid formation of channels between injectors and producers that leave large areas of the reservoir unreachable by injected fluids. Infill drilling parallel horizontal wells for horizontal well CHOPS at any time in the flood’s life cycle could effectively reach these areas. Shutting down fluid injection in floods after the wells have been placed would mitigate loosing circulation in channels created by the flood.

1,500m horizontal wells in the previously mentioned Lloydminster zone produced at 7 to 15 times the rates of the off-setting vertical wells. At these rates drilling and initial completion pays out in an acceptable length of time. Follow-up horizontal well CHOPS sequential re-completion production rates will be lower but re-completion costs are an order of magnitude less than drilling a vertical well. This lower cost for 16 re-completions per horizontal well makes less prolific zones attractive long life resource plays.

Successful horizontal well CHOPS should leave a marginal amount of residual oil. If the remaining volume of oil becomes economically attractive, the length of reservoir directly accessed by parallel horizontal wells would improve the effectiveness of secondary recovery schemes.

Thirty-five years ago practically no one could imagine that a progressing cavity pump would be competitive with a pumpjack and rod pump, let alone that it would totally replace them and create a step change in profitability and recovery of cold heavy oil.

Similarly, until today, it would have been challenging to consider that another step change in cold heavy oil recovery and profitability could be achieved by causing sand laden fluid production from horizontal wells.

We know that oil prices cycle. Low oil prices provide auspicious circumstances to begin the process of sequential re-completion of economically depleted horizontal wells such as:

A dormant paid out capital asset can be re-activated and re-completed for about 60% the cost of drilling a new vertical well to maintain production and cashflow.
Equipment and services are typically less expensive during times of low oil prices.
Greater than 50% of the estimated initial re-completion cost is equipment that is expected to serve the 20+ years life of a horizontal CHOPS well.
Proof of profitable incremental recovery would emerge about the time the oil price cycle is beginning to increase adding value to reserves.