SPE-173959-MS
Production Optimization using Insert Progressing Cavity Pumps (I-PCP) and Hydraulic
Equipment for Heavy Oilfields in Mexico
L. Jimenez Carreno, and C. Yudiche Barbosa, Weatherford de Mexico; B. Villalobos
Ramirez, DIAVAZ Group
Copyright 2015, Society of Petroleum Engineers
This paper was prepared for presentation at the SPE Artificial Lift Conference Latin
America and Caribbean held in Salvador, Bahia, Brazil, 2728 May 2015.
This paper was selected for presentation by an SPE program committee following review of
information contained in an abstract submitted by the author (s). Contents of the paper have
not been reviewed by the Society of Petroleum Engineers and are subject to correction by the
author(s). The material does not necessarily reflect any position of the Society of Petroleum
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Abstract
Implementation of compatible production technologies for extraction of heavy oil using
progressing cavity pump (PCP) systems in three different oilfields: Altamira, Ebano, Panuco
& Cacalilao; located in Northeastern Mexico. The optimization process was accomplished
thru implementation of Insert Progressing Cavity Pumps (I-PCP) and hydraulic driveheads, in
areas without electric power network, and high restrictions of well service rigs.
The project started with conventional PCP, and a second phase achieved an important
operational improvement thru I-PCP and surface systems with smaller internal combustion
engines in response to the operators request for less fuel consumption. In 2008 January a
conventional PCP was installed in the Franco Espaola-66 well (60 BFD & 1000 m lifting
capacity), successfully operating for 2 years. Subsequently between 2008 and 2009, 32
additional PCP were installed, but the operator company had serious restrictions for
optimization programs because of unavailability of well intervention rigs.
In response for January 2010, an I-PCP was installed in the Altamira-1022 well (189 BFD &
1500 m lifting capacity), for extraction of heavy oil (10-13 API); the favorable results led to
installation of over 200 additional PCP systems in shallow wells (450 m). At the same time,
80 power generators as surface equipment were installed in Ebano field; this due to the
absence of electricity in the area. Those generators used 4.3 and 5.7 liter internal combustion
engines. Those wells had low gas-oil ratio (GOR), therefore the use of natural gas obtained
from annulus (casing-tubing) was not an option, so an outsourcing of Liquefied Petroleum
Gas (LPG) was required. Considerable financial costs for high daily gas consumption were
caused by this situation.
Facing this condition, the first hydraulic surface equipment with smaller capacity (3.0 L) was
installed for January 2012, showing a decrease in gas consumption and lower costs. Likewise,
the new application was focused on shallow wells, during next two years, in which all of the
initial engines were replaced.
This PCP optimization process showed several positive economic impacts:
Decrease of intervention rig frequency regarding former PCP systems installed, which
demanded pulling of production tubing string.
Saving in time and cost in front of PCP failures due to lower operating time using flush-by
units, in comparison with bigger intervention rigs; i.e., workover or maintenance rigs.
Lower deferred production levels were obtained.
Additional cost saving associated to the consumption of LPG.
Implementation of this PCP process as artificial lift system for heavy oil wells achieved
important improvements regarding operational performance and well productivity.
Introduction
The optimization process using I-PCP, and hydraulic driveheads in areas with no
electrification, was focused on Ebano field because the potential of those installations was
there; in cuantitative terms: Altamira (20 wells), Ebano (176 wells), and Panuco-Cacalilao
(17 wells).
Ebano is an oilfield located at Mexico northeastern near to Mexico Gulf, the first commercial
well Pez No. 1 was perforated in April 1904 (the oldest one in Mexico); it is a mature
oilfield characterized by heavy oil, and production pumps seated in vertical zone (300-400
m), therefore named shallow wells.
Based on that the implementation of an operation model based on high viscosity and shallow
wells, in surface and subsurface, has been developed; and operator company always has
searched for new technologies or methods to assure required reliability for the field. The
following figures (1,2, and 3) summarize the main characteristics of Ebano field.
Statement of Theory and Definitions
Since the first efforts to apply progressing cavity (PC) pumping as method of artificial lift in
the early 1980s, they have experienced a gradual increase in the petroleum industry, and
today there are more than 100,000 wells worldwide operating on-shore and off-shore with
these PC systems. That is mainly because overall efficiencies of 50% to 70% are evidenced,
which is higher than any of the other artificial lift types.
Conventional PC pumps are installed by running the stator assembly on the bottom of the
tubing string and rotor on the bottom of the rod string, however the insert or insertable
progressing cavity pumps (I-PCP) have the entire pump assembly installed via the rod string
and landed inside the tubing string enabling the pump to be pulled and rerun via the rod
string; both of them incorporating a torque anchoror no-turn tool to prevent back-off of pump
components.
The primary advantage of I-PCP system is the elimination of costly and time consuming
tubing pulls to change worn or damaged pumps or to switch to different pump
sizes/configurations as downhole pumping requirements change. Another potential benefit is
avoiding the need to pull and rerun downhole instrumentation with tubing. Note that because
the entire pump assembly must fit within the production tubing there is a limitation in terms
of the compatible pump models for a given tubing size which in turn reduces the maximum
rate and volume that can be produced relative to conventional tubing deployed systems.
The I-PCP can be installed in different tubing sizes (2-7/8, 3-1/2, 4-1/2, 5-1/2), and using
two separate methods. The conventional method is through the use of a Pump Seating Nipple
(PSN) in the tubing string and corresponding set of seating rings in the pump assembly. The
second method is through the use of an anchor which allows I-PCP to be run in wells either
not equipped with a PSN, or when the PSN is at the wrong location or its specifications are
unknown. The seating rings can be configured as top or bottom hold down.
The system is run and deployed by lowering to the target position (PSN or anchor landing
depth). Retrieval of the I-PCP is done by pulling the rod string upwards to remove the seating
rings from the PSN, or unseating the anchor if it was used. Once at surface the I-PCP can be
inspected and normally redressed, if required, on the well site and rerun. I-PCP systems have
application for a wide range of requirements depending on displacement capacity and lifting
neccesary; Figure 4 shows these ranges for different tubing sizes.
Related with surface equipment for PC systems, the basic functions of a surface PC drive are:
Suspend the rod string and carry the axial loads.
Deliver the torque required at the polished rod.
Rotate the polished rod at the required speed in a safe manner.
Provide for safe release of the stored energy during shut-downs.
Prevent produced fluids from escaping the system.
To achieve those functions, PC drives typically comprise thrust bearings, a transmission
system (fixed gear or sheaves & belts), braking mechanism (or recoil control system), and a
stuffing box. They are designed for applications where a large range of horsepower and
polished rod speed are required; and two main configurations are identified based on prime
mover used: Electric Motor, and Internal Combustion Gas Engine; the last one aka Hydraulic
Equipment.
The Hydraulic Equipment basically consists of a hydraulic motor, and is powered by a
hydraulic skid unit (skid). The skid has an electric or gas prime mover which drives a
hydraulic pump. Fluid flow from the pump then drives the hydraulic motor on the drive,
which in turn, drives the rod string. The hydraulic power unit is completely assembled with
an enviro-skid, tank, pump, hoses and oil. The pressure compensator on the pump is preset to
requirements for automatic torque control. The speed control is easily adjustable in the field
with a turn of a knob, located on the pump.
For backspin control a backspin retarder is built into every hydraulic power unit with a check
valve in the hydraulic lines on the pressure side of the motor. When the drive is turning in the
forward direction, the check valve is forced open by fluid flowing into the motor. When the
drive spins in reverse, the check valve is forced closed and drains the fluid at a slow,
controlled rate of speed. In order to ensure that there is no loss of suction in the motor the
backspin speed is very slow.
These units can be driven optionally through belts and sprockets, and the hydraulic motor
mounted on a slide frame or on a wellhead frame with a detachable stuffing box. The hinged
belt guard on the drive completely encloses the belts and sheaves but provides easy access
and maximum safety. The drive units hollow shaft is coupled to the polished rod through a
polished rod clamp. Inside the drivehead, large roller bearings support the rod string and fluid
column. A sturdy wellhead frame supports the assembly with a variety of stuffing box
options available.
All drivehead assemblies must be are equipped with a polished rod and booth guards as
standard safety equipment. See the Figure 5 for a broad understanding.
Description and Application of Equipment and Processes
In Ebano field the I-PCP design was moved away from a bottom hold down configuration
because there was the risk of solids being produced fall down between the stator and the
tubing wall, decreasing the chances of successfully pulling the pump to surface. In a top hold
down installation that type of issue is drastically reduced, although there is still a chance that
it will be stuck downhole due to solids however it will be because the solids have
accumulated above the pump discharge.
In those cases solids can be removed with flushing activities, or if there is access to coil
tubing unit, and the pump surfaced without pulling the tubing. In the bottom hold down
application always the tubing string has to be removed to surface the pump, at margin of
quantity of solids being produced, even if it is a trace amount, it will fall out of solution and
accumulate over time.
Accordingly, PCP well planning in Ebano field included installation of PSN into all of the
wells at initial completion. The PSN and seating rings were located at the top of the
assembly, reducing the chance of sand packing in the annular space between the pump and
the tubing. Besides a special rotor design was used to allow flushing without an extended
flush tube, makes it easier to handle and install, while providing ability to flush sand from the
pump and pump intake without unseating the pump or pulling the tubing.
The rotor features a unique shaped tip which mates with a floating ring at the top of the insert
assembly, acting as a no-go. When these two components make contact, the entire assembly
can be pulled along with the rod string. When a flush is required, the rotor-end is positioned
between the upper top of the stator and the floating ring chamber, in a 4 (1.2 m) extension
tube or orbit tube, extending the rest of the rotor into the production tubing. Once the rotor is
positioned, fluid can be flushed around the rotor and through the stator. Other advantage is
this specific configuration reduces the length of the assembly during running and pulling
when compared to other insert PCP designs. See details in Figure 6
.
The elastomer used for I-PCP installed in Ebano field was an improved version of traditional
high nitrile elastomers, wich had better resistance regarding high water cuts, gas, and
explosive decompression; with a superior performance in gassy applications containing CO2
and/or involving chemical products where other elastomers experienced chemical swelling;
those all advantages keeping mostly the resistances concerning solids, H2S, and maximum
fluid temperatures.
The PC Pumps have demonstrated effectiveness as the best artificial lift system installed in
Ebano oilfield, in that way the applications validated so far have been insert PC Pumps (I-
PCP), driveheads with hydraulic skid, and energy generator sets with 3.0 liters combustion
engines in surface. I-PCP improved working time because the stator and rotor can be
reemplaced with versatile units called flush by units, decreasing intervention rig costs, and
optimizing production time; i.e., selection of I-PCP models based on characterization of
fluids, and pressure load. Surface equipment (hydraulic or electric) using 3.0 L
engines minimized the consumption of LPG which represents a proper selection of PCP
surface equipment in agreement with maximum torque and horsepower requirement.
Graphics 7,8, and 9 show all pumps run and their average performance. Conventional PCP
were the first installed (2008-2009), I-PCP from 2010-2014. In total 383 pumps historically
installed in Ebano field.
The nomenclature of pumps used is in accordance with ISO rules where the first number
represents nominal displacement capacity expressed in m /day/100rpm (or Bbl/day/l00rpm),
and the second number the maximum operating lift in m (or ft) as dimensional units.
Results and Conclusions
The insertable PC pumps (l-PCP) provided in Ebano field have been focused on reduction in
well servicing time and costs, allowing pump volume / lift changes without having to pull
tubing. Those pumps use PSN and seating rings located at the top of assembly, reducing the
chance of sand packing in the annular space between the pump and the tubing.
The l-PCP mostly used in Ebano field because good performance for displacement and lifting
requierements have been 11-1800, 14-1200, 17-1000 y 30-1500 models; i.e., cost/benefit,
which even represent the pumps currently requested by the operator oil company and are
considered for their production optimizacion plans.
The first observable positive impact was reduction about 40% of intervention rig annual
frequency in PCP systems previously installed, conventional pumps, which demanded pulling
of production tubing string. In the Figure 10 the evolution of some representative PCP wells
over the time can be observed relating to service units utilized for well interventions.
In economic terms, the well interventions aimed at changes on installed artificial lift systems
had 90% approx. of money saving because the service cost of flush-by unit was about
US$6,100/service by comparison with US$42,675/day using a traditional rig (maintenance or
workover); in addition the intervention time for pulling and running was 1-2 days for a flush-
by unit, versus 3-4 days for the second case.
Besides, getting lower production losses associated to minor off-line well times was a parallel
and very important achieved benefit. Those benefits by lower costs and deferred production
were observed with higher impact when well programs included extra operational activities
such as bottom sand cleaning, redesigns or re-completions. Figures 11 and 12 illustrate a
representative example of optimization level achieved in Ebano field, wells Ebano-1042 and
Ebano-1043, where the cost difference between a conventional PCP and I-PCP system after
two well services can be noticed.
And fewer than 33% of oil production loss (50 BOPD; US$ 87.7 Bbl lifting cost) during their
interventions, planned only for PC pump replacements but one of them (Ebano-1043 well)
including change from conventional PCP to I-PCP in the second well service.
The optimization process also included energetic improvement at surface which was obtained
with the implementation of smaller combustion engines as prime movers for PCP systems,
changing from 4.3 & 5.7 to 3.0 Liters combustion engines in surface, and achieving inferior
daily LPG consumptions. As example, Figure 13 shows detailed requirements for one typical
operative month (March 2013) regarding gas demand in hydraulic skid and genenerator set
(GenSet), with differents engine capacities (5.7L, 4.3L,3.0L); clearly evidencing that 3.0L
engine was the most economical option.
Figure 14 is a good example of optimization process implemented at surface level, showing
monthly and annual costs for PCP equipment installed in two Ebano PCP wells; where the
cheapest configuration was systems using hydraulic skids with 3.0L engine, and a cost
savings of 28.5% was recorded. There are similar data for other periods, equipment, and
wells under the same optimized operational conditions.
And Figure 15 represents the comparision between the two years with higher PCP well
population because completion campaign in Ebano field, 2012 and 2013, and the associated
costs to LPG consumptions
Lastly, the following are potential opportunities of improvement to Ebano field in the future,
keeping the focus on getting better performances, higher run life, reduction of intervention
cost and downtime:
Evaluation of new available elastomer, which represents the next generation of high nitrile
elastomer with upgraded properties to wear, higher temperatures, gassy applications
containing CO2, and explosive decompression compared to the current elastomer; in addition
the bonding system reacts better with their elastomer components resulting in higher bond
strength.
Consider the operational accesability of I-PCP as production system for well programs
including chemical stimulations.
Intallation of I-PCP along with continuous rod deployed by a flushby unit equipped with
injector.
Running of downhole monitoring equipment (sensor / gauges) which can remain in place
during pump servicing.
Implementation of I-PCP anchors throughout the accomplishment of proper field trials and
respective widespread increase, which allows I-PCP redesigns (relocation in depth) or
runnings in wells either not equipped with a PSN or when the PSN is at the wrong location or
its specifications are unknown.
Acknowledgedments
Authors are thankful for the opportunity to prepare this paper from the Operator Oil
Company of Ebano field, and their involved representative who provided valuable
information.
Likewise thanks to Weatherford Int. for all support and encourage about it.
References
Soltys, T., Svitich, J. 2008-2014. Progressing Cavity Pumps Training Documents.
Weatherford International, Global Product Line Manager, Edmonton, Alberta, Canada.
