Much work has been done on the operation of beam pump pump-off controllers, but the downtime is normally a simple timer and the optimum downtime is usually set by rule of thumb or trial and error. This paper uses a complete well model coupled with a transient reservoir  model to show that the optimum downtime in terms of total energy used per produced barrel of oil is equal to the wellbore storage time from well test analysis.

In today’s world it can be challenging to locate the downhole well location immediately below the surface location in secondary and tertiary projects. There are several factors that must be considered when picking the surface location that will maximize value including 1) increases cost of building a location and drilling, 2) increases cost of artificial lift and operations, and 3) production rate and reserve impact.  This paper will explore how these factors can be put in an Excel Spread Sheet to assist in picking the location that will maximize value. 

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.

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.    

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 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.

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.

 

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.

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. 

Vortex Tools addresses the challenges of managing/optimizing hydrocarbon liquids recovery from horizontal wells with long laterals, thereby increasing their economic value. A 2014 five-well case study with a regional independent found that deploying Vortex downhole DX-I tubing tools (in conjunction with gas lift and plunger) saw beneficial increases in oil & gas production, along with a significant increase in water removal, in horizontal and deviated wells. Injection gas rates were also reduced after Vortex was added, but saw increased gas to sales, as well as lower/smoother tubing and casing pressures. Vortex was deployed at the end of tubing, in the horizontal/lateral portion of the well (~80° of deviation). With Vortex tools installed, oil production increased significantly. In one reported case, the oil production increased from 80 barrels to over 400 barrels per day. A two-year lookback on these wells also showed a beneficial decline curve in all cases.

This is a discussion of a newly developed and field tested system to measure and track fluids produced in the oilfield.  The system’s mission is to track the fluid movement from the cradle to the grave and is, for the most part, a “hands off-no humans needed” custody scheme that provides precise verifiable electronic information to the producer, the trucking company that hauls the fluids, and the companies that handle the final deposition of the fluids, either at the disposal well or the pipeline terminal. 

The discussion centers on a West Texas well where the use of this system saves over $10,000 per year in operating costs.  The paper discloses patented technology as well as how the implementation process evolved and overcame the paradigms and mindsets of the people and companies.  Developing new technology is cake walk when compared to altering the complexity of the “oilfield thought” process.

 

Automation is a crucial element to modern production facilities in the Permian Basin.  However, most facilities engineers lack basic understanding of automation and therefore cannot properly design or implement an automated system.  This paper will discuss automation and instrumentation basics as part of a broad automation philosophy to help readers understand how individual components fit into a complete design.  Individual components (or instruments) will be examined to share what options are available to industry and how they can best be utilized.  An analysis of four common field development scenarios will help facilities engineers grow their knowledge and be better prepared to implement automation into their facilities.

 

Many sucker rod lifted wells are operating at less than 30% electrical efficiency, because the downhole gas separator installed in the well is inefficient.  Free gas interfering with liquid filling the pump is a major operational problem encountered in producing Sucker Rod Lifted wells.  Gas interference is when free gas at the pump intake enters the pump filling displacement volume with gas in place of liquid, then significant loss in liquid production, reduced drawdown, increased failures and inefficiency occurs.  Installing an incorrectly designed gas separator is the most common problem.  Installing very long separators does not increase separator capacity or efficiency.  Restrictions in the annulus above the pump intake such as tubing anchors result in reduced annular gas flow with gas preferentially entering the pump.  A downhole gas separator has a maximum liquid capacity.  Casing size restricts the maximum size gas separator that can be installed in a well.  The separator used in a well should be designed for the well configuration/conditions.  Gas Separators with high separation efficiency should be used to effectively produce sucker rod lifted wells.

The pump stroke can be longer than the surface stroke when the dynamic motion of the beam pump system adds momentum to the rod string, resulting in the pump stroke length increasing.  The pump stroke can be shorter than the surface stroke when sucker rods stretch to pick up the pump fluid load and other frictional forces.  Rod stretch creates under travel dynamometer card shape.  Pumping fast or high plunger velocities creates over travel cards. 

Pump position in the barrel changes when the pump is not full compared to a stroke when the pump is filled with liquid.  When incomplete pump fillage occurs, the plunger tends to over travels on the down stroke moving deeper into the barrel.  In some cases tagging can occur due to pump spacing, plus increased over travel.  This paper will use field collected dynamometer data to show excessive over-travel can occur on both the upstroke and the down stroke.  

 

Corrosion fatigue (CF) is an important concern for structures that are exposed to cyclic loads in corrosive environments, especially in the case of oil and gas operations like drilling, offshore risers or sucker rods in artificial lift. Considering the current combination of complex wells completions and the increase of water cuts, the CO2, H2S and Bacteria represent a higher risk for CF failures in sucker rods. This combined effect force operators to choose a steel for either corrosive environments or high loads and increase the chemical inhibition programs.

In response to the new downhole challenges, a research and development program (R&D) has been created to analyze the key factors that affect sucker rods performance under CF. As a result of this R&D program, a new corrosion-fatigue resistance sucker rod has been developed. The present paper summarizes the development process, the new sucker rod characteristics and its performance.

This paper will discuss reducing failures in rod pumped wells by using best practices and design changes. The theme of the paper is to share solutions observed over the last 41 years while working with rod pumped wells. These best practices applied from the polished rod through the bottom hole assembly have been proven to improve run time between failures. The topics discussed are improper installation of equipment along with the effect of a properly designed bottom hole assembly. I will also highlight pump designs and accessory items to help with sand and gas issues. When you lower your failure frequency you are reducing exposure to potential accidents benefiting us all.

Production challenges in horizontal wells are caused by slug flow behaviour from the horizontal. In response, Production Plus developed the flow conditioning HEAL System to mitigate slug flow before fluids enter the downhole separator and pump. Slug flow mitigation allows rod pumping to be more effective and efficient, offering a solution for low-cost OPEX to reliably maximize drawdown.

This paper analyzes multiple HEAL System installations in the Permian Basin that transition from gas lifting to HEAL System rod pumping. It explores requirements for intermediate artificial lift systems, challenges achieving production forecasts, slug flow and solids production mechanisms, and impact from horizontal trajectories.  The discussion compares recent long-term, multiple case studies that statistically demonstrate the impact of flow conditioning on well production economics. It offers insights into long-term NPV benefits achieved by transitioning from gas lifting to the HEAL System with rod pumping.

Evolution of annular gas lift candidates and early results of application in the Delaware Basin. 

Tubing leaks account for half of the failures in the Bakken wells. The root cause is coupling on tubing wear due to the non-metallic guides wearing out.  

In order to combat this problem, ToughMet 3 TS95 sucker rod couplings were installed in up to 250 wells to significantly reduce the failure rate in the field.  Several individual case histories will be discussed to demonstrate the lifetime extension and reduced wear rates seen with the use of the new couplings.

Additional benefits have been observed, particularly increased fluid production, increased pump fillage, higher Fluid loads, and lower gearbox loads. XSPOC data will be presented for several wells to demonstrate the positive effects observed in the field.

Rod pump service data provides valuable insight into wellbore conditions and the efficacy of the rod lift system. Trend analysis of metrics such as reason for well pull and pump component evaluation provides increased visibility about individual well performance issues and more broadly, about field performance. Comprehensive pump service data is an indispensable supplement to an operator’s internal data in well review meetings for the purpose of improving optimization efforts. This paper will focus primarily on how this data may be used to benefit two key factors: performance and design.

There are thousands of marginal wells in the Permian Basin with potential to produce significantly more oil and gas with the assistance of plunger lift.  Working with multiple operators in the Permian Basin, PLSI has installed plunger lift systems in these type wells and realized significant increases in oil and gas production.  The common characteristic is fluid downhole which never makes it to the surface production facilities.  This fluid loads up the wellbore downhole which increases hydrostatic back pressure on the formation that holds back production.  By installing a plunger lift system, we have seen wells that were producing a few barrels of fluid per day double oil or gas production. This paper will present production data from operators showing increases in production and revenue with minimum expense that resulted in significant increases in net operating income. 

Horizontal drilling and the need for effective completion techniques has given birth to a wide variety of solutions in North American oil and gas plays. For many operators, it has become a top priority to optimize proppant distribution using buoyancy enhancer additives and to achieve fracture diversion with clean solutions that do not require intervention. At the heart of these initiatives is the Permian Basin, which is being revitalized through the use of intelligent completion technologies to make those priorities a reality.

This paper proposes two solutions that can be customized for an integrated fluid system that helps improve proppant distribution, deepen proppant penetration within the complex fracture network, increase proppant pack volume, and increase maximum proppant concentration that can be placed. By improving proppant placement and increasing the fracture volume occupied by proppant, operators can enhance conductivity of the fracture network, resulting in improvements to initial and long-term production.