Unplanned rod lift system outages often lead to long and costly repairs in addition to direct production loss. Leveraging design knowledge of the rod lift system combined with real-time condition monitoring represents a promising avenue to mitigate this problem. This study will demonstrate an application of advanced monitoring and diagnostic analytics on data from vibration, strain, current and voltage sensors installed in critical locations of a beam pumping unit.

When pumping conditions deviate from the norm, the operators are alerted with regard to pending failures, and a supervisory control layer takes immediate action to adjust the operational pumping speed profile to maintain production at a safe operational level or shut down the equipment in the event of imminent catastrophic failure.

This paper will review the sensor installations and data acquisition approach. Experimental field test results will be presented and discussed.

Producers can spend a significant amount of money repairing a sucker rod pump system without fully understanding the root cause of a failure. Incomplete, missing or incorrect data and over reliance on a supplier to “fix the problem” can be ineffective. Following “best practices” developed in other fields or generic “rules of thumb” may also lead to higher than expected failure rate especially in unconventional reservoirs.

Common practice of a “like for like” replacement may experience an early life failure resulting in another workover. This increases lifting cost and contributes to unfavorable well and field economics.

During the down stroke the plunger in a rod pump must fall through a barrel that is filled with fluid. The plunger will establish a free fall velocity that is determined by the forces resisting downward motion. The free fall of the plunger may not be large enough to correspond to the actual velocity necessary to match the pumping speed set by the pumping unit. In this case the plunger must be pushed into the barrel by a compressive force in order to match the pumping velocity. The compressive force may be large enough to cause buckling in the lowest section of sucker rods. The purpose of this paper is to test this hypothesis by presenting measurements of the free fall velocity of a plunger in a liquid filled barrel and the pushing force necessary to exceed the free fall velocity of the plunger in the barrel. Simple models are shown to relate the measurments to practice.

Variable Speed Drives (VSDs) are a popular rod lift control system for operators that are willing to pay a premium for the promise that they can squeeze every last drop from a producing formation. However, initial results from the Eagle Ford suggest that VSDs may not be worth the additional expense when compared to the performance of their less complex cousin, the Pump-Off Controller (POC). In particular, high CAPEX and maintenance costs along with performance issues on gassy, sand producing, shale wells are leading some operators to choose POCs over VSDs for unconventional reservoir applications. 

Furthermore, brief disruptions in production have less of an impact on the reservoir inflow of tight shales than that of higher permeable conventional reservoirs. This study is based on the examination of the performance of Eagle Ford wells that were initially controlled by VSDs and then swapped to POCs.

Variable Speed Drives (VSDs) are a popular rod lift control system for operators that are willing to pay a premium for the promise that they can squeeze every last drop from a producing formation. However, initial results from the Eagle Ford suggest that VSDs may not be worth the additional expense when compared to the performance of their less complex cousin, the Pump-Off Controller (POC). In particular, high CAPEX and maintenance costs along with performance issues on gassy, sand producing, shale wells are leading some operators to choose POCs over VSDs for unconventional reservoir applications. 

Furthermore, brief disruptions in production have less of an impact on the reservoir inflow of tight shales than that of higher permeable conventional reservoirs. This study is based on the examination of the performance of Eagle Ford wells that were initially controlled by VSDs and then swapped to POCs.

There is a growing awareness in the oilfield of the problems generated due to horizontal wells’ long lateral lengths, undulation fluid and gas trapping capabilities, inconsistent and aggressive unloading behaviors, and limitations on historically and widely applied separation methods.  Due to these impacting factors, horizontal rod pumped wells must address the resultant production behaviors as well as operational issues that can be worsened by poor application of old and non-optimal downhole separation and poor pump placement practices.  It has now been proven in a multitude of applications and formations across the US that the use of a safely and correctly placed isolated tailpipe used in series with a diverter style of separator can help alleviate challenging production issues in horizontal rod pumped wells, resulting in substantially increased production output as well as reduced failures and lower operational costs.    

A discussion on different types of corrosion and wear (and their associated mechanisms) will be followed by an overview of commercially available mitigation techniques including their practical field applications downhole. Commonly available information that can be used to determine exactly why downhole failures occur will be reviewed.  The importance of using preferred life extension procedures to maximize the Mean Time Between Failures (MTBF) and solve the root cause(s) of downhole failures are also covered.  Finally, this paper includes a review of various metallurgical options, nonmetallic materials, chemical treatments, mechanical methods, liners and coatings currently used downhole focusing on the advantages and limitations of each product.  Commonly accepted practices and myths about downhole corrosion and wear will be exposed.

The objective of this paper is to assist production, completion, artificial lift and enhanced recovery engineers in understanding and avoiding downhole corrosion and wear failures cost effectively.

The last few years there has been quite a bit of advancement in the fiberglass sucker rods (FSR).  The published ratings across the fiberglass industry have increased over 20% with some manufactures going much higher.   What other benefits have come along with this increase?  Have there been any drawbacks?  This paper will discuss proper design criteria including importance of well specific criteria.  With load ratings increasing as much as they have a better understanding of the dynamics of the wellbore are needed as many companies are realizing further cost savings by substituting smaller rod body diameters and getting similar productions.  Lastly this paper will present some preliminary data on compression testing being performed and how that has correlated into the successes for the FSR installed in the field.

Production testing with digital electronic devices has been discussed for about 20 years amongst a small group.  The idea has been implemented a few times with uncertain results.  The uncertainty exists because the measurements were done with turbine meters which are themselves uncertain.  

Recent testing has been accomplished by gauging calibrated tanks.  We believe these measurements of liquid volumes can be viewed as perfect.  Measurement of gas is done with computerized orifice meters which are known to be accurate as long as the correct orifice size is used.

This presentation compares perfect production tests made with tank gauges and test made with imperfect digital-electronic devices.  What would the oilfield look like if testing with digital0electronic devices became the norm?

 The concept of Pump Stroke Optimization was introduced in September 2015 at the ALRDC Sucker Rod Pumping Workshop.  Significant benefits to the sucker rod pumping system are obtained by preferentially slowing the downstroke (when pump capacity exceeds a wells productivity), while keeping a fast upstroke. These benefits are: Less pump slippage, less gas interference, and higher pump fillage, which results in less strokes per day for the same production, which results in less downhole wear. Higher minimum load translate into less rod buckling forces. 

Pump Stroke Optimization also includes automatic adjustment of upstroke and downstroke speeds to keep from overpumping wells, and is particularly effective for horizontal oil wells.

The results of a 20 well 2016 test program will be presented.

Depressed oil prices drive producers to reduce operating expenses and maximize profit margins. Some of these expenses are necessary for day-to-day operations, and are dictated by vendor pricing. Others are a function of the operator’s activity, and can be controlled within certain limits. Workover costs are a prime example of these “controllable” expenses. That being said, well failure control programs are essential to maximizing profits and limiting expenses.

In 2014, Resolute Energy recognized the need for a more effective failure program in their Gardendale, TX asset. Through organizational, managerial, and engineering efforts, Resolute successfully decreased well failures by nearly 90 year-to-year, resulting in expense savings of nearly $4.5 million. 

These savings, along with other expense control efforts, cut lifting cost in half throughout the 101 wells. This paper describes these control efforts in detail to reinforce their importance, particularly in current market conditions.

The conversion from ESP to rod pump is needed when well-inflow is insufficient to supply enough fluid to the ESP. However, achieving good pump performance in rod pump systems operating in depleted wells with high gas/oil ratio can be limited as well. Creating a multi-stage gas separator system which removes free gas before fluid entered the pump intake increases volumetric efficiency in depleted wells. The first stage is a slotted intake where gas can coalesce. The second stage utilizes three large gas separator bodies for increased expansion of free gas which travels with the fluid by action of an extended dip tube. Finally, a vortex tool which creates a centrifugal force increases free gas separation efficiency.

A successful case study in Goldsmith is presented in this paper to demonstrate significant pump efficiency increase resulting from enhanced separator design based on downhole conditions to create a more efficient production system.

 

Poor performance in rod pumping wells using downhole gas separation tools is not uncommon. The stems from a lack of evaluating well conditions before inserting a template gas separation tool which can handle liquid production and free gas in the system. Evaluating well conditions before designing the downhole gas separation tool while applying static & centrifugal principals have led to increased success for recent installations.

This paper reviews cases studies where evaluations of well conditions dictated BHA design for downhole gas separation systems and improved the overall pump efficiency in poorly performing wells with high gas volume.

Field case studies for the patented Sand Flush Plunger™ (patent #8,535,024) have been performed at the Hwy 80 field operated by Pioneer Natural Resources. Pump repair and well conditions data was collected from the pump and well tracker systems used by the service providers of the field. 

Standard pump repair information dated since 1989, while the Sand Flush Pump begun usage on 2009.  Interestingly, the results show that the average run time for the Sand Flush Pump is 840 days out of 560 well workovers that used it, while for a Standard Pump (Metal and Grooved Plunger) is 561 days out of

5313 workovers. Within the 560 wells that have tested the Sand Flush Plunger, 165 used both types of plungers providing a more detail correlation. From these, the Sand Flush averaged 1307 run days compared to the 604 days of a Standard Pump.

Gassy low pressure stratified reservoirs require special jet pump well completion and equipment selection considerations. These reservoirs often experience a 50% reservoir pressure decline within the first 14 months of production but can continue to produce for many years below the saturation pressure. Jet pumps can be installed in wells in many ways. The most common, lowest cost and simplest well completion design is the “casing free installation”, but as reservoir pressure declines below the saturation pressure, gas liberation often results in gas accumulation and slugging under the casing packer that is used in this design.

Beam pumping systems have proven successful in the Permian Basin for many years. The beam pumping system allows gas separation and gas flow up the casing annulus. A concentric coil tubing jet pump well completion offers downhole gas separation with options to improve desired effects. Successful case histories are presented to support the application.

Sandy wells are a common problem for any artificial lift system. Calculating the correct allowable volume of sand and solids’ particle size may be the missing link in optimizing run-times and establishing solid pump performance.

Recent Colombian ESP case studies were conducted in fields with high sand/solids presence. Where run times typically lasted 5 months or less, a new design to improve ESP performance introduced a Cup Packer and screens below the ESP sensor.

Once ESP variables such as intake pressure, drive frequency, and temperature were considered, the unit conditions stabilized and improved performance followed, greatly extending run times, and reducing unnecessary intervention costs.

 

Some Colombian oilfields have medium to heavy oil production and high gas volume in wells.  Gas production is one of the biggest limitations in an ESP system, as they have difficulty handling a high amount of free gas.  In many cases even when an ESP is used in conjunction with a gas separator and gas handlers, the amount of free gas exceeds the capacity of the system and the performance of the pump is not improved.

For a complex well of this oilfield which produced 2.2 MMCF/D (represented around 20% of the total gas produce in this Oilfield). (OSI) designed a double stage gas separation system.  The ESP design consisted of a vortex ESP gas separator, gas handler, shrouded ESP + downhole gas separator with the intake installed below the shroud.  This combination proved to be successful with strong pump performance.

 

We will show in multiple cases studies the effect of relieving back pressure on a oil well has in relationship to the producing bottom hole pressure, pump efficiency and over all economics of the well.

Re-utilization of company owned artificial lift equipment and parts is a common practice among operators and service providers across the industry.  It is common practice for operators to resize artificial lift equipment at failure or proactively as economics allow. During resizing activity, it is not uncommon to utilize company owned equipment and inventory to satisfy the hydraulic lifting requirements of the system.

In this paper we share how we leveraged our internal data and along with Q-rod to classify and rank our pumping unit population of over 6000+ wells across our EOR and Unconventional Assets in the Permian Basin. This application was developed using industry standard object-relation database systems, languages, and visualization software. As a result, the project has promoted a company-wide reduction in new purchases of pumping units and motors for the last three years which has supported reducing operating expenses.

 

Metal to metal contact shortens the run life of both tubing, steel and fiberglass sucker rods.  Using sacrificial rod guides can extend this life at the expense of increased side and axial loading enhanced by Coulomb friction effects.  The problem is not limited to directional and horizontal wells.  Just how crooked are our vertical wells?  Simple inclination surveys insufficiently describe the wellbore path drilled.  Knowledge of failure history, inclination and azimuth of wellbore path, plus access to a rod design program provide insight into effective placement of rod guides and longer run life.  A case history from an established West Texas waterflood is presented to illustrate the application.

The balance-ported valve is a gas-lift valve that allows full, available gas injection pressure to be used for the unloading and operating valves.  Using full injection pressure allows for a deeper point of gas injection, which lowers the FBHP, thereby increasing total production.  With standard IPO valves, it is necessary to design the valves with casing pressure drops in order to close the valves as the injection point moves deeper.  The balance-ported valve is configured such that no design casing pressure drops are required for closing.  The pilot valve can be utilized later in the life of the well, once the injection point is at the bottom valve and the well is producing less than 150 BFPD.  The pilot valve controls injection into the well in self-intermitting cycles, allowing the well to feed in between these cycles. This allows for lower gas injection rates and increased production.

Downhole dynamometer cards can be generated by predictive and diagnostic wave computer programs. Those generated by the diagnostic program are best for trouble shooting as they are calculated from a measured surface card. Several aspects of the bottom cards are presented in discussed in this paper some of which are well known and used and some which are less recognized.

For cards showing gas fill, the location of the TV closing is not the location in the downhole stroke where liquid fill begins. However it is close for low pressure wells. The shape of the load release can indicate if the well has low or high intake pressure. The pump load is indicated if the card is scaled correctly and generated by approximately correct damping or drag coefficients along the rod. A delayed opening of the SV on the upstroke can indicate that the pump is not tightly spaced. The load release distance is incorrectly identified as an area where compression is occurring but this does not indicate compression in the rod above the pump but is where gas, is present, is being compressed below the TV and above the SV. Example are shown of the above.

If looking at only the downhole card, excursions below where the load pick-up began indicate a compression load in the rod above the pump. However high damping coefficients will reduce the apparent fluid load shown on the bottom hole dynamometer and will  also reduce the amount the bottom card may be showing apparent rod compression at the pump so the damping coefficients have an effect on apparent compression at the bottom hole card and these effects are illustrated. The shape of the bottom card can suggest if the damping coefficients are low or high. In general the predictive programs do not indicate compression at the pump unless pump resistance is guessed by the user but the bottom cards can indicate compression but the magnitude of indicated compression also depends on input for the diagnostic computer program.

Both the predictive and diagnostic programs can, under certain circumstance, indicate compression uphole from the pump due to dynamic effects. This can occur even with no pump resistance or rod compression at the pump.  Rod failure characteristics can show if the rod broke after repeated compression (pump resistance) but this is after the fact.

These factors and more are discussed and illustrated to hopefully make problem recognition easier for the operator.

New unconventional wells have been a huge challenge for ESPs in the Permian Basin because in horizontal wells with high-formation GORs or GLRs, the pumped fluid can cause issues such as gas interference, gas locking, short run life, low production, poor energy efficiency, increased failure rates, shutdowns, so forth. A major problem is gas presence around the ESPs, it causes the motor to rapidly overheat because the gas is incapable of adequately cooling.

For this application, a double stage of gas separation was designed to break the gas slug and avoid gas entrance into ESPs by forcing free gas to go around the shroud and produce through the casing, and the fluid is forced to pass through an additional gas separator (Guardian Shield), this tool helps to separate gas to keep lower motor temperature. These novel applications help operators to reduced OPEX (operating expense) by minimize well Interventions, decreasing failures in the pump due to overheat, and allow the ESP to operate in gassy wells with high GLR, stabilizing the production and reduce the unforeseen interruption.

 

Murphy is currently operating 500 beam pumped wells in the unconventional Eagle Ford Shale play in South Texas. There are numerous challenges to beam pumping operations in the Eagle Ford, which included paraffin, corrosion, solids, deviated wellbores, slug flow, and foamy gassy fluid.

One of the challenges, deviated wellbores, led to an increased frequency of failures due to metal to metal contact between the rod coupling and the tubing. The development of a rod guide strategy has significantly reduced the failure frequency of tubing and parted rod couplings due to wear.

The development of the strategy includes data from the failure data base, the use of tubing scanning, the proper placement of the guides and the use of the proper guide material.

With the proliferation of production from multiple zones within wells, a major challenge long recognized by industry is to understand which zones are contributing, and how much. This is even more of a challenge with multiphase flow from different zones and with the advent of hydraulic fracturing, correctly identifying which zones have the potential to contribute is critical for future operations. 

A new solution to this problem is to use a jet pump in combination with inflatable packers and a new PLT that uses Patent Pending Doppler sensors rather than spinners to measure flow. This allows the in-flow to be accurately measured while the zone is isolated, with the added benefit of being able to draw the pressure down to assess the potential of the zone when on lift. 

This paper discusses the application of this new method of production logging in a vertical well in West Texas. It will also show the logs obtained in the test well.