alrdc 2016 niobrara plungerlift compression...

ALRDC 2016 Niobrara Horizontal Well Deliquification via Plunger Lift and Enhanced Controls Compression Arthur Beecherl, Verdad Oil & Gas; Aaron Baker and Jason Fortner, Flogistix L.P. This paper was prepared for presentation at the 2016 ALRDC Conference held in Denver, Colorado February 29 – March 2, 2016.

This paper was submitted for presentation to the ALRDC Workshop Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been peer reviewed and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Artificial Lift Resource and Development Council.

Abstract

In the Denver Julesburg Basin, the primary means of artificial lift for natural gas well deliquification is plunger lift. However, horizontal well production is often limited by varying gathering system pressures or insufficient lifting force, and experience considerable down time in order to build the required working pressure. In cases of substantial liquid loading, wells may require a swab rig, which directly impacts lost production and lease operating expenses. By integrating plunger lift with “enhanced controls” compression systems, horizontal wells can be effectively deliquified, limiting production down time and increasing net revenue generation. The goal of “plunger lift compression” is to manage a well’s flowing pressure, decreasing the lifting force required to bring the fluid column to the surface. Over time, the well is able to perform a higher frequency of plunger cycles, carrying smaller fluid volumes on each trip. Enhanced compressor controls play a critical role in the process. The compressor responds to changes in the well’s flowing pressure and automatically adjusts its throughput as needed during the plunger cycle. The compressor is designed to allow the well to flow freely to the sales infrastructure in the initial period of a plunger cycle. As the well approaches critical velocity and its corresponding flow rate decreases, the entirety of the production gas is diverted through the compressor. Thereby

allowing the compressor to control the well’s flow rate and plunger velocity, and ensuring that the fluid column successfully surfaces. The compressor installation should include a bypass line and check valve, allowing the well to surge into the sales line at the initial opening of the well. The compressor will automatically start, shift speed, and assume control of the well in coordination with decline of the well’s initial velocity. Adjustments to the set points of the plunger lift controller are also crucial to the deliquification process, in allowing the well to initiate a plunger cycle as soon as the minimum lifting force requirements are met. Verdad Oil, in conjunction with Flogistix L.P., has demonstrated a successful model for deliquifying Niobrara horizontal wells, resulting in stabilized production and consistent monetary returns. Introduction

The following case study examines the impacts of implementing compression as a means of artificial lift operating in direct conjunction with plunger lift. The goal of this analysis is to determine whether the addition of “enhanced controls” compression to plunger lift on a producing horizontal well has a significant impact in stabilizing production. In turn, making further optimization of plunger lift controls more consistent.

The well being examined, named Well #82 for the purposes of this case study, is a Niobrara horizontal well, located near Lochbuie, Colorado. The well has been producing since April of 2015, and following initial production, a plunger lift system was installed. As bottom hole pressure declined, inconsistent production resulted due to liquid loading and fluctuations of the gathering system pressures.

The data examined covers a period of 36 days prior to the installation of the compression system, which took place on

2 Niobrara Horizontal Well Deliquification via Plunger Lift and Enhanced Controls Compression

October 14th, 2015. This data is weighed in comparison to a period of 76 days with active compression.

It should be noted that a control was not utilized as an independent variable in this case study.

Principles of Operation The operational theory behind “plunger lift compression” is to utilize the compressor to maintain critical velocity of the fluid column and plunger during significant periods of a plunger cycle. The well is allowed to flow freely into the gathering system when the well has sufficient pressure in excess of the gathering system pressure. When the well reaches a point where the required lifting force is not met, the compressor reduces the upstream Static pressure, enabling the plunger and fluid slug to successfully surface and unload the well. The term “enhanced controls” compression refers to the algorithmic logic built into the compressor, which is responsible for the compressor’s state change. The compressor’s state change is critical in quickly responding to the initiation of a plunger cycle and maintaining an optimal flow rate. The success of plunger lift as a stand-alone means of artificial lift is dependent on a number of factors. A well’s gas-to-liquid ratio (GLR), reservoir pressure, and gathering system pressure are often the primary factors that determine the viability of plunger lift. Gathering system pressure is of critical importance given that it is an external factor that has a direct impact on a well’s ability to unload liquids. Changes in gathering system pressure include, but are not limited to, downstream compressor stations, piping diameters, seasonal freezing, introduction of additional production, and internal diameter constriction due to liquid or paraffin build up. Sudden or prolonged increases in gathering system pressure result in erratic plunger cycles, longer shut in periods, and liquid loading that can result in the well being swabbed.

Enhanced controls compression is implemented as the controlling mechanism to stabilize the gathering system pressure and allow the well to flow against a reduced line pressure during key periods of a plunger cycle. At the initiation of a given plunger cycle, the well will flow a portion of its gas directly into the gathering system. This allows the well to utilize it’s available lifting force and the corresponding flow rate is not limited by the compressor. As the Casing and Tubing pressures drop, the plunger velocity and flow rate begins to decrease. As this occurs, the compressor transitions to managing 100% of the produced gas. Once the compressor has assumed control of the well’s flow rate, it will begin to reduce the static pressure, resulting in a stable plunger velocity. After the plunger surfaces, the well can begin an Afterflow cycle if desired. Configurations of the compressor control system can enable the compressor to react to the plunger arrival and alter its throughput during the period of Afterflow. When the motor valve closes to allow the plunger to descend, the compression system will then engage its internal recirculation to remain in a standby condition until the next cycle occurs. In the event that the well is shut in, the compressor can shut down, and will automatically restart at the beginning of the next plunger cycle. In the event of a mechanical issue, the control system is capable of preventing a well cycle and reporting a problem over the SCADA network, thereby decreasing the likelihood of liquid loading and additional down time. In addition to the on-skid compression controls, the FLUX telemetry system is utilized for remote monitoring and data collection. The compressor trend data is used for alarm messaging, system optimization and evaluation of capacity utilization. Well Profile Production Company: Verdad Oil and Gas Well Name: #82 Well Type: Horizontal Producing Formation: Niobrara Total Vertical Depth: 7,240’ (horizontal leg) Lateral Length: 4,200’ Collar Placement: +/- 40 degree (7,100’ MD)


Artificial Lift Profile Plunger Type: 18”, 4 Slot, Caged Bypass Compressor Type: 108mm Rotary Screw Compressor Driver: GM 5.7L Engine Performance Results Performance Prior to Compression During the period of September 8th thru October 14th, Well #82 had an average Casing pressure of 467.12 psig and a Tubing pressure of 228.68 psig (Table 1). The well was flowing against an average Static pressure of 133.74 PSIG. Due to the lifting force required to lift the fluid column and plunger, the well often missed plunger arrivals and experienced mandatory shut in periods. There were also instances where the well had to be swabbed in order to resume production (Graphs A&C). Excluding the missed plunger arrivals, the average plunger arrival time was 20.20 minutes (Table 1). The plunger arrival time is measured from the point that the motor valve opens to when the plunger arrives at the lubricator. The average differential pressure between the Casing and Tubing was 238.44 psig. Differential pressure between the Casing and Tubing is indicative of the fluid column that has built up in the annulus and Tubing string. An analysis of a two-hour window on September 27th, gives a more detailed view of individual cycles (Graph F). During this time period, Well #82 successfully completed three plunger cycles, with an average plunger arrival time of 28.67 minutes, which based on a shut in time of 14 minutes, amounts to 33.75 plunger cycles per day (Table 3). Given a collar depth of approximately 7,100 feet, the average plunger velocity was 248 feet/minute. Performance With Enhanced Controls Compression During the period of October 15th thru December 31st, Well #82 had an average Casing pressure of 323.11 psig and a Tubing pressure of 178.16 psig (Table 1). With the compressor now managing the static pressure during certain periods of the plunger cycle, the static pressure was

reduced to 94.97 psig. During this time span, production remained stable and consistent. The average plunger arrival time was 14.66 minutes (Table 1). The average differential pressure between the Casing and Tubing was reduced to 144.95 psig. In looking at an alternative two-hour window on November 11th, there is evidence of a substantial shift in the run time of the well (Graph G). During this time period, Well #82 successfully completed five plunger cycles, with an average plunger arrival time of 13 minutes. With the aid of the compressor, the shut in time was reduced to 9 minutes. Based on these values, the well was now cycling at a rate of 65.45 times per day at an average plunger velocity of 546 feet/minute (Table 3). Performance Comparison The production impact was evident with the addition of the compression system based on several factors discussed. The well was able to cycle at a much higher frequency with compression. Average plunger arrival times across the period of analysis decreased by 5.54 minutes and the static pressure was reduced by 38.77 psig. By comparing the Casing and Tubing pressure differential, there is an evident reduction in liquid loading at the plunger’s seat nipple. The differential pressure was reduced by 93.49 psig, with an overall lowering of Casing pressure by 144.02 psig (Table 1). The effect of decreased hydrostatic loading on the bottom hole pressure increases the differential pressure across the producing zone and facilitates gas and liquid ingress to the well bore. Comparison of the two-hour windows of production, the average plunger arrival time was decreased by 15.67 minutes and the average plunger velocity increased by 299 feet/minute. The combination of faster plunger cycles and decreasing the shut-in time by 5 minutes enabled an average increase of greater than 30 plunger cycles per day. This is an increase in cycle frequency of 93.9%. During individual plunger cycles, the compression system was able to reduce the Static pressure to


approximately 75 psig within 7 minutes of each cycle. Gathering System Pressure Spike On December 2nd, 2015, a midstream event occurred, which caused the gathering system pressure to increase from 150 psig to 300 psig. Without the compression system in place, this incident would have likely resulted in extended down time between cycles, and possible liquid loading. The event is captured on the compression system’s telemetry record as Discharge pressure (Graph I). Despite the increase in midstream pressure, the compressor’s control of the well’s static pressure enabled the well to continue producing reliably. Three cycles in that time period had slightly extended shut in times for building pressure (Graph H) and overall plunger arrival times were between 17-20 minutes, with zero non-arrivals. Economic Analysis Table 4 displays the income statement for Location #82 from September thru December 2015. Tangible and intangible costs have been removed from the income statement. Expenses incurred due to liquid loading as well as lost production will, overtime, offset the cost of compression. Individual costs relating to swabbing can range from $500 to $1,500, depending on the duration of the work. Without compression in place, costs associated with swabbing will likely increase as reservoir pressure declines. In considering lost production, a single day of down time across the time period of this study averaged 261 mscfd of gas, and 61.5 barrels of oil per day. According to the U.S. Energy Information Association, the average oil price for this time period was $42.64 (WTI-Cushing). The average natural gas price (Henry Hub) was $2.36. Excluding marketing costs, this amounts to a daily revenue loss of $3,238.32.

Inconsistent production also increases the internal labor cost of frequent site visits in order to address issues and restore production. Operational efficiency is critical in the current production environment and the ability to focus on optimization as opposed to lost production events is paramount. Conclusion Implementation of enhanced controls compression in conjunction with plunger lift has resulted in the successful deliquification of the well. This is evident in the consistent reduction in differential pressure between the Casing and Tubing pressures. Further, the well has been able to cycle at a much higher frequency, with reliable plunger arrivals. Within the limits of the study’s time frame, it is apparent that the well’s decline curve has been shifted upwards, and the decline rate has been stabilized. This is visible on the production summary graph (Graph B), which displays the daily production totals. Without the addition of enhanced controls compression, liquid loading and subsequent production loss would have likely increased. Acknowledgements / References U.S. Energy Information Administration, http://www.eia.gov Verdad Oil & Gas Corporation, http://www.verdadoil.com Flogistix, LP, http://www.flogistix.com Patriot Artificial Lift LLC, http://www.patriot-lift.com


Exhibits Graph A

Graph B


Graph C

Graph D


Graph E


Graph F

Graph G


Graph H

Graph I


Graph J

Graph K


Table 1

Table 2

Table 3

Table 4

FlowRate(MCFPD) Casing(PSI) Tubing(PSI) Static(PSI) ArrivalTime(Minutes)PriortoCompression 221.13 467.12 228.68 133.74 20.20WithCompression 244.68 323.11 178.16 94.97 14.66Difference 23.55 144.02 50.52 38.77 5.54

AveragedComparisonofTrendDataPoints(September8thtoDecember31st)

Tubing-StaticOverride TubingatCycleStart Casing-TubingDifferential StaticPressurePrior to Compression 196.00 330.23 245.04 135.77With Compression 185.00 244.78 147.76 91.50Difference 11.00 85.45 97.28 44.27

2HourAverageComparison(September27thvsNovember11th)

Arrival Time (Minutes) CyclesPerDay ShutInTime(Minutes) Plunger Velocity (Ft/Min)Prior to Compression 28.67 33.75 14 248With Compression 13.00 65.45 9.00 546Difference 15.67 31.70 5.00 299

2HourAverageComparison(September27thvsNovember11th)

INCOMESTATEMENT:LOCATION#82Sep Oct Nov Dec Total

REVENUEOilRevenue400150-OilIncome $73,314.86 $77,252.19 $65,192.54 $49,559.20 $265,318.79

2015

OilRevenueTotal $73,314.86 $77,252.19 $65,192.54 $49,559.20 $265,318.79GasRevenue400110-GasIncome $23,793.80 $30,231.92 $22,077.89 $18,769.10 $94,872.71GasRevenueTotal $23,793.80 $30,231.92 $22,077.89 $18,769.10 $94,872.71REVENUETOTAL $97,108.66 $107,484.11 $87,270.43 $68,328.30 $360,191.50

TAXESANDOTHERDEDUCTIONSSeveranceTax600103-GAS-ProductionTaxes $237.94 $302.32 $220.78 $187.69 $948.73600104-OIL-ProductionTaxes $733.15 $772.52 $651.93 $495.59 $2,653.19600111-COLORADOGASCONSERVATION $16.66 $21.16 $15.45 $13.13 $66.40SeveranceTaxTotal $987.75 $1,096.00 $888.16 $696.41 $3,668.32OtherTax600107-COLORADOOILCONSERVATION $51.32 $54.08 $45.63 $34.69 $185.72OtherTaxTotal $51.32 $54.08 $45.63 $34.69 $185.72TAXESANDOTHERDEDUCTIONSTOTAL $1,039.07 $1,150.08 $933.79 $731.10 $3,854.04

LEASEOPERATINGEXPENSELeaseOperatingExpense550010-LeaseOperatingExpenses $1,000.00 $1,000.00 $1,000.00 $1,000.00 $4,000.00550070-CHEMICAL/CHEMTREATMENT $200.04 $200.04550075-Communications $413.36 $130.71 $126.34 $88.24 $758.65550085-Compression $3,167.96 $3,115.90 $3,115.90 $9,399.76550180-FluidLevels $221.03 $221.03550360-PullingUnit $558.27 $558.27550375-Pumpers $1,796.74 $1,796.74550400-RegulatoryExpense $587.15 $1,013.03 $282.34 $1,882.52550415-RoustaboutServices $3,264.08 $3,264.08550450-SaltWaterDisposal $186.43 $169.15 $355.58550490-Supervision $1,080.00 $2,568.81 $1,200.00 $1,200.00 $6,048.81550500-Swabbing $1,166.00 $541.00 $1,707.00550520-SWABBING $462.00 $462.00550590-Utilities $1.89 $0.56 $2.45550615-Water/WaterHauling $389.28 $569.50 $730.00 $1,688.78LeaseOperatingExpenseTotal $6,011.23 $13,565.01 $7,082.99 $5,686.48 $32,345.71LEASEOPERATINGEXPENSETOTAL $6,011.23 $13,565.01 $7,082.99 $5,686.48 $32,345.71

OTHEREXPENSEMarketingExpense600112-GAS-PurchaserDeduction $11,352.50 $14,010.54 $11,468.36 $10,073.93 $46,905.33600113-OIL-PurchaserDeduction $0.00 $0.00 $0.00 $0.00 $0.00MarketingExpenseTotal $11,352.50 $14,010.54 $11,468.36 $10,073.93 $46,905.33AdValoremExpense600120-AdValoremTax $3,665.74 $3,862.61 $3,259.63 $2,477.96 $13,265.94600121-GASADVALOREMTAX $1,189.69 $1,511.60 $1,103.89 $938.31 $4,743.49AdValoremExpenseTotal $4,855.43 $5,374.21 $4,363.52 $3,416.27 $18,009.43OTHEREXPENSETOTAL $16,207.93 $19,384.75 $15,831.88 $13,490.20 $64,914.76NETINCOME $73,850.43 $73,384.27 $63,421.77 $48,420.52 $259,076.99


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