Marcellus Drilling News reported recently that Eclipse Resources once again had the top producing oil well with their Purple Hayes well in Guernsey County. Purple Hayes is currently the longest horizontal well drilled in the United States at 3.5 miles long with Marcellus Drilliing News calling it “the gift that keeps on giving, quarter after quarter.”
In a conference call reported in Oil & Gas 360 in 2016, Eclipse Resources Chairman and CEO Ben Hulburt talked about the completion of the Purple Hayes well.
“We have completed our Purple Hayes well which was designed to completely change the cost structure and return profile of Ohio Utica Shale drilling by maximizing lateral length while also optimizing completing techniques.
“In drilling the Purple Hayes well to a completed lateral length of 18,544 feet, remarkably, in just 18 days, with a 100% slick water completion design consisting of 124 stages or approximately 100 feet per stage – 150 feet per stage at a pace averaging over five stages per day.
“From a cost perspective this translates into a steep reduction in total costs per lateral foot, which is almost 30% better than our lowest cost well previously drilled and far below any other company drilling in the Utica Shale.
“Our concept in drilling was to enhance the return profile of the Utica play by determining the technical limit of lateral length in the liquid portion of our acreage to confirm our estimates of total well cost. And finally to assess the recoverability per foot of lateral against our recovery seen in shorter 8,000 foot laterals to 10,000 foot laterals.
“After conducting a very extensive engineering review and redesign process which brought several innovative ideas together. We eommenced drilling this well at a lateral length that was actually a bit shorter than what we believe is our technical limit. Although we did not notice at the time, we [have been told] by our service company partners that they believe this to be the longest onshore lateral ever drilled in the United States if not the world.
“From the cost perspective I’m very proud to say we drilled and completed this well at less than a 5% variance from our regional costs estimates at $15.8 million. We put the well directly into sales earlier this week and the final test to determine the recoverability per foot of lateral is now underway. While it will take a number of months to have a sense for the long-term performance, we are very excited about the very initial production and pressure numbers we are seeing after the first 48 hours of production testing.
“One thing I want to stress, is we believe strongly that the managed pressure draw down production methodology will maximize the long-term performance of the well. We do not manage our wells for maximum 24 hour IP rates just to get a headline which we believe is meaningless and detrimental to well performance.
“We are very encouraged to already be producing at our managed shale target production rates for this well in less than 48 hours of production.”
In the same conference call, Tom Liberatore, Eclipse COO, discussed the well in further detail.
“As Ben mentioned, after months of work and planning, the company recently drilled and completed its extended-reach lateral well which we call the Purple Hayes well. In order to successfully drill and complete this well, we fully relied on the deep knowledge base and expertise of one of the most sophisticated operating teams in the Appalachian Basin.
“This leading edge well has an 18,544 foot completed lateral with the total measuring depth of 27,048 feet and was drilled in an impressive 17.6 days. Following conversations and confirmation with industry sources, we believe this is the longest U.S. onshore lateral ever drilled and completed.
“We successfully completed the well with 123 of 124 plans frac stages at an average pace of 5.3 stages per day. And perhaps most importantly, we had no issues completing the toe stages of the well where the greatest risk of completion issues might have risen.
“With the cost of $15.8 million or $854 per lateral foot, we not only believe this proof of concept is repeatable but we have also identified a few areas we can improve on to further reduce cost on subsequent wells.
“On the completion side, we utilized the states facing of 150 feet which was tighter than our typical well design and completed the well with 100% slick water. The well was put to sales on May 3rd and is being produced using our aggressive managed choke production method that is intended to tightly control the pressure drawdown over time to attempt to maintain what we believe to be the pressure dependent permeability of this formation and maintain pressure above dew point in the reservoir as long as possible.
“After the first 24 hours of flowback into sales, the well was producing at a wellhead rate of approximately 5 MMcf per day, of what we expect to be approximately 1,300 BTU gas, and 1,200 barrels of Condensate with flowing tubing pressures of approximately 3,200 pounds. Since that time we have seen the gas rate continue to increase as the well cleans up and we will be targeting a stabilized initial wellhead gas rate of 5.6 MMcf per day.
“Based on our processing models and wells in the area we expect an NGL yield of approximately 80 barrels to 90 barrels per MMcf assuming ethane rejection and a post-processing gas shrink of approximately 15%. The current Condensate yield is in line with our original estimates of approximately 175 barrels to 180 barrels per MMcf of gas.
“At this point we are very excited about these very early stage results. However, it is obviously still very difficult to draw definitive conclusions about the long-term performance of the well. We will be evaluating its performance over the coming months to determine if the recovery per foot of lateral is in line with our shorter lateral type curve expectations for the Condensate areas.
“After we have studied the well performance for a longer period of time we will be able to better estimate reserves and returns and develop extended lateral type well estimates. But our initial estimates are that if this well performs as expected, we help to reduce our individual well F&D cost in the Condensate area by approximately 20% to 30%, which would improve well returns by 35% to 70% over our current shorter lateral type well returns in the area.
“While this well was drilled in the Condensate area of our acreage, the technologies, design, and techniques we use can be applied across our entire acreage position allowing us to continue to extend our lateral lengths in the Rich Gas and Dry Gas portions of the Utica Shale. As we move eastward towards our Dry Gas acreage, the depth and pressure of the Utica Shale continues to increase, so we expect that our lateral length will decrease accordingly.
“We still believe we can drill wells with lateral lengths of at least 15,000 feet even in the deepest Dry Gas east area of our acreage. By substantially lowering our cost per lateral foot, we are attempting to increase the returns and decrease our breakeven cost across all of our areas of over 100,000 acreage position which includes our highly rich Marcellus Shale acreage in Eastern Ohio. I’m very pleased with this team and their efforts to innovate in order to enhance the overall value of our assets in this difficult pricing environment.”