U.S. patent application number 11/508552 was filed with the patent office on 2008-02-28 for methods & systems for the automated operation and control of a continuous loop pump.
Invention is credited to Donald B. Vaello.
Application Number | 20080047705 11/508552 |
Document ID | / |
Family ID | 39112284 |
Filed Date | 2008-02-28 |
United States Patent
Application |
20080047705 |
Kind Code |
A1 |
Vaello; Donald B. |
February 28, 2008 |
Methods & systems for the automated operation and control of a
continuous loop pump
Abstract
Systems and methods for automating the extraction of oil from an
oil well, especially low production orphan wells. The system
includes an endless loop pump extending into the oil well; a
rotational drive motor operably connected to the loop pump; a
transfer pump for conveying petroleum product away from the endless
loop pump; a microprocessor controller for controlling the
rotational drive motor and transfer pump; a number of sensors for
sending operational measurements to the microprocessor indicative
of the operational characteristics of the rotational drive motor; a
collection reservoir for gathering the petroleum product from the
endless loop pump; and a liquid level sensor for sending a level
measurement to the microprocessor indicative of the level of the
petroleum product in the collection reservoir. The system includes
a variable sheave-pulley configuration and arrangement as well as
complete local and remote system monitoring and reporting. The
methods include automated production transfer (and reporting) to
storage facilities (tank battery); automated starting and stopping
of the loop pump in response to production variations; and improved
safety processes for the containment, capture, and processing of
casing head gases and liquid products.
Inventors: |
Vaello; Donald B.; (Hondo,
TX) |
Correspondence
Address: |
KAMMER BROWNING PLLC
7700 BROADWAY, SUITE 202
SAN ANTONIO
TX
78209
US
|
Family ID: |
39112284 |
Appl. No.: |
11/508552 |
Filed: |
August 22, 2006 |
Current U.S.
Class: |
166/250.15 ;
166/369; 166/66; 166/68.5 |
Current CPC
Class: |
E21B 43/126
20130101 |
Class at
Publication: |
166/250.15 ;
166/369; 166/68.5; 166/66 |
International
Class: |
E21B 43/16 20060101
E21B043/16; E21B 47/00 20060101 E21B047/00 |
Claims
1. A system for automating the extraction of oil from an oil well,
the system comprising: (a) an endless loop pump extending into the
oil well; (b) a rotational drive motor operably connected to the
loop pump; (c) a microprocessor controller for controlling the
rotational drive motor; and (d) at least one sensor for sending at
least one operational measurement to the microprocessor controller
indicative of the operational characteristics of the rotational
drive motor.
2. A system for automating the transfer of petroleum product from
an endless loop pump, the system comprising: (a) a collection
reservoir for gathering the petroleum product from the endless
pump; (b) a liquid level sensor for sending a level measurement
indicative of a level of the petroleum product in the collection
reservoir; (c) a transfer pump for conveying the petroleum product
away from the endless loop pump; and (d) a microprocessor
controller for controlling operation of the transfer pump.
3. A system for automating the extraction of liquid petroleum from
an oil well, the system comprising: (a) an endless loop pump
extending into the oil well; (b) a rotational drive motor operably
connected to the loop pump; (c) a collection reservoir for
gathering the petroleum product from the endless loop pump; (d) a
liquid level sensor for sending a level measurement indicative of
the level of the petroleum product in the collection reservoir; (e)
a transfer pump for conveying the petroleum product away from the
endless loop pump; (f) a microprocessor controller for controlling
the rotational drive motor and the transfer pump; and (g) at least
one sensor for sending at least one operational measurement to the
microprocessor controller indicative of the operational
characteristics of the rotational drive motor.
4. The system of claim 3 wherein the microprocessor controller
further comprises: (a) an endless loop pump control module for
controlling operation of the endless loop pump; (b) a liquid level
control module for monitoring and recording a level of liquid
petroleum product in the collection reservoir; (c) a gas flow
control module for monitoring and recording a volume of well head
gases collected by the endless loop pump; (d) an alarm module for
monitoring and reporting alarm conditions in the operation of the
system; and (e) a communication module for data transfer and
reporting to and from a remote location.
5. The system of claim 4 wherein the rotational drive motor further
comprises a variable speed motor and the endless loop pump control
module serves to control the variable speed.
6. The system of claim 4 wherein the at least one sensor comprises
a torque sensor which communicates torque measurements to the
endless loop pump control module for controlling the operation of
the rotational drive motor.
7. The system of claim 4 wherein the liquid level control module
receives input from the liquid level sensor and thereby serves to
control the operation of the transfer pump for a predetermined time
interval to convey the liquid petroleum product away from the
collection reservoir.
8. The system of claim 3 further comprises a well head gas
collection system whereby the well head gas is conducted away from
the endless loop pump.
9. The system of claim 8 wherein the well head gas collection
system further comprises a gas pressure sensor and a controllable
valve and the microprocessor controller serves to operate the
controllable valve upon input from the gas pressure sensor to
conduct the well head gases away from the endless loop pump.
10. The system of claim 3 further comprising an intrusion detection
system.
11. The system of claim 4 wherein the alarm module communicates
alarm conditions in the operation of the system to a local alarm
broadcast device.
12. The system of claim 4 wherein the communication module
communicates data between the microprocessor controller and a
remote system by wireless means.
13. The system of claim 3, further comprising a pressurizable
system enclosure, the system enclosure comprising: (a) a liquid
product enclosure generally defining the collection reservoir for
containing the liquid petroleum product collected by the endless
loop pump; and (b) a gas product enclosure for collecting the well
head gas product collected during operation of the endless loop
pump.
14. The system of claim 13 wherein the system enclosure further
comprises a means for mounting the endless loop pump.
15. The system of claim 3 further comprising: (a) a hydrophobic
material loop member extending into the oil well to a point below
the surface of the liquid petroleum in the oil well; and (b) a
plurality of pulleys at the surface of the oil well whereby the
hydrophobic material loop member traverses and is driven by the
pulleys and the petroleum liquid is extracted from the hydrophobic
loop into the collection reservoir by tension between the
pulleys.
16. A method for automated operation of a transfer pump operable in
association with an oil well endless loop pump, the method
comprising the steps of: (a) providing an automated controller
connected to the transfer pump; (b) monitoring a collection
reservoir liquid level associated with the endless loop pump; (c)
initiating operation of the transfer pump when a liquid level in
the collection reservoir exceeds a specified limit; (d) measuring a
volume of liquid product transferred from the collection reservoir;
and (e) communicating to a remote location a record of the transfer
of product.
17. A method for automated operation of an oil well endless loop
pump and a transfer pump associated therewith, the method
comprising the steps of: (a) providing an automated controller
connected to a drive motor on the endless loop pump and to the
transfer pump; (b) monitoring a torque experienced by the drive
motor; (c) triggering an alarm when the torque exceeds pre-defined
limits; (d) monitoring a liquid level in a collection reservoir
associated with the endless loop pump; (e) initiating the operation
of the transfer pump when the collection reservoir liquid level
exceeds pre-defined limits; (f) measuring a volume of liquid
product transferred from the collection reservoir; and (g)
communicating to a remote location a record of the transfer of
product.
Description
BACKGROUND OF THE INVENTION
[0001] 1. Field of the Invention
[0002] The present invention relates generally to systems and
methods for pumping fluids from subterranean formations. The
present invention relates more specifically to systems and methods
for the automated control of a continuous loop pump utilized in
conjunction with low production oil and gas wells.
[0003] 2. Description of the Related Art
[0004] Production practices associated with present day oil and gas
wells have changed very little over the last hundred years. While
there have been significant improvements in secondary and tertiary
reservoir recovery techniques, very little has been done to improve
the overall operational management model for implementation of the
basic technology associated with the typical oil field. Most, if
not all, secondary and tertiary recovery programs continue to reach
their economic limit of production while still leaving a
significant percentage of production in the reservoir.
[0005] The primary recovery of petroleum products from subterranean
formations is most frequently accomplished by relatively
inefficient pumping devices that become cost effective simply
because of the volume of production initially available within the
well. In other words, the high cost of operating the pump equipment
is offset by the volume of petroleum product that is removed from
the well in the process. As production declines in a formation, the
cost effectiveness of these energy consuming, primary production
pumps drops off rapidly.
[0006] Efforts have been made in the past, therefore, to provide
pump systems that operate more efficiently and are cost effective
for low production wells. In fact, the largest obstacle to
production from low producing wells is overcoming the large capital
equipment investment and lease operating costs that are required to
remove product from a reservoir. Present day production equipment,
much of which dates back over 70 years, is primarily designed to
remove large amounts of fluid from the reservoir under continuous
operation. Such technologies offer little in the way of operating
efficiency to the present day stripper well producer, who for the
most part is trying to remove only a few barrels of production per
day from the well bore. Most stripper well producers therefore
operate their pumping equipment less than one hour per day. This
results in extremely poor utilization of financial capital, labor,
and equipment.
[0007] In addition to the above-described limitations involving
operational technologies, there is currently very little in the way
of information technology and performance reporting that is
available to inform a well operator if the equipment being utilized
is efficiently producing unless and until field personnel
physically visit and inspect the well site. Producers that operate
multi-well leases (which is typical of stripper well operations)
generally require that field personnel visit and inspect each well
for proper operation. Such onsite inspections and control
activities, however, provide little in the way of recent production
numbers or per well operating performance. Present on-site
technologies, especially with stripper well production, do not
incorporate, or employ well monitoring, frequency or time of
service personnel visits, or production recording equipment. At
present, lease production is typically reported and managed by a
measurement of how much oil is actually delivered into the
production tanks and not by how much, if any, of the individual
wells contributed to the overall production.
[0008] In addition to the above-described operational problems,
present day technologies that are brought to bear upon wells that
are found to be in a generally inoperative state typically involve
large and expensive installation machinery referred to as "pulling
units" to pull the well, repair and restore operations. This
present day machinery is costly both in terms of the equipment and
the labor associated with its operation. It is not uncommon,
therefore, for pulling and repair operations to absorb most, if not
all, of the annual profitability of a well under a low production
environment.
[0009] Efforts have been made in the past to develop systems and
techniques for the more efficient removal of petroleum products
from low producing wells. One such approach is commonly referred to
as continuous loop pump technology (CLPT). This type of pump
utilizes a continuous flexible member, such as a rope or "mop",
that is moved about a sequence of pulleys or sheaves and drive
wheels. The loop of material is directed from a surface location to
a subterranean location within the formation holding the fluid to
be produced from the well. The use of a continuous flexible member
structured in this manner, in conjunction with an array of sheaves
as a means to pump fluids from a well, has been documented in the
United States as early as 1908. Some early systems utilized what is
referred to as Couette flow and other fluid mechanics principles in
an effort to improve their efficiency.
[0010] Continuous loop pump technology (CLPT) has shown great
promise in reducing oil well initial capital outlay and ongoing
operating expense. CLTP can provide a very effective means for
recovering oil and/or gas from wells that have otherwise reached
their economic limits of production (stripper wells) by
conventional production practices. Despite this promise, previous
efforts at utilizing continuous loop pump technologies have failed
to address system automation, diagnostics and reporting, as well as
safety issues related to operation and production. In addition,
previous systems have not provided flexible, cost effective pumping
mechanisms that overcome the various conditions that must be
addressed in the removal of multi-viscosity fluids and gases, or
the conditions associated with variable well depths and casing
environments. Examples of some of the efforts made in the past
include systems of the type described in the following patents:
[0011] U.S. Pat. No. 4,712,667 issued to Owen on Dec. 15, 1987
entitled Device for Recovering Fluidfrom a Well, describes a
continuous chain loop pump with oil carrying cavities attached
within each chain link. The system also includes an improved oil
wiper and brush system for use in low producing, or otherwise
un-pumpable hydrocarbon wells.
[0012] U.S. Pat. No. 5,080,781 issued to Alexander on Jan. 14, 1992
entitled Down-Hole Hydrocarbon Collector describes an improved
drive assembly for an endless belt type of pump that utilizes a
number of rollers to collect hydrocarbon fluids in specific gravity
separating receptacles. The single drive motor described operates
the belt drive rollers, as well as a reciprocating pump to transmit
the production fluid to a remote collection site. The entire
assembly is designed to be placed inside of the well bore.
[0013] U.S. Pat. No. 5,423,415 issued to Williams on Jun. 13, 1995
entitled Surface Assembly for Rope Pumps describes a system that
utilizes a pair of multi-wound sheaves to drive a rope pump at high
speeds and further describes a pressurized containment housing to
capture and direct gases and fluids for production. The system
described references certain command and control functionalities,
but does not specifically describe the systems or methods to
address the control solutions.
[0014] U.S. Pat. No. 5,048,670 issued to Crafton et al. on Sep. 17,
1991 entitled Flexible Conveyor Assembly and Conveying Apparatus
and Method for Lifting Fluid describes the utilization of Couette
flow principles wherein the rope of a continuous loop rope pump is
loosely encased in a flexible tube to improve the collection of
hydrocarbon liquids.
[0015] Other efforts along the same lines as those described above
have included: U.S. Pat. No. 930,465 issued to Fowler; U.S. Pat.
No. 1,017,847 issued to Carl; U.S. Pat. No. 1,703,963 issued to
Scruby; U.S. Pat. No. 1,740,821 issued to Kneuper; U.S. Pat. No.
2,121,931 issued to Sloan; U.S. Pat. No. 2,289,706 issued to Hay;
U.S. Pat. No. 2,329,913 issued to Kizziar; U.S. Pat. No. 2,380,144
issued to Bohannon; U.S. Pat. No. 2,704,981 issued to Gustafson;
U.S. Pat. No. 3,774,685 issued to Rhodes; U.S. Pat. No. 4,652,372
issued to Threadgill; U.S. Pat. No. 4,712,667 issued to Jackson;
and U.S. Pat. No. 6,158,515 issued to Greer et al.
[0016] Most of the above efforts in the past to address the
utilization of continuous loop pumps have focused on specific
optimization for particular viscosities of petroleum fluids or
particular depths of formation. Some efforts have been made to
modify the manner in which the fluids are removed from the
continuous loop member through an array of pulleys or fluid
extractors. Little if any effort, however, has been made to address
the operational efficiencies of continuous loop pumps in general
and the necessity of labor intensive operational control over such
systems. In the end, each of the pumps described in the prior art
requires the above-described constant monitoring and/or
intermittent operation such that efficiencies gained by slight
improvements in the components of the system are more than offset
by the ongoing labor costs and equipment costs still associated
with such low production pumping systems.
[0017] Wells that have reached the limits of their efficient
primary production operation, and which may typically be shut down
as a result, are frequently referred to as "orphaned wells". In
general, an orphaned well is a well for which the operational
authorities have issued a permit but for which production of oil or
gas under such authority's jurisdiction has not been reported for
at least twelve months. The current shortage in petroleum
production has resulted in legislation in some jurisdictions that
is designed to encourage the adoption of such orphaned wells by
providing certain benefits and exemptions deriving from future
production from these wells.
[0018] At present there are thousands of "orphaned" wells available
for "adoption" in the U.S. (over 11,700 in Texas alone), the
majority of which are considered in the industry to be "stripper
wells". A stripper well is a generic term for a marginal well or a
well that has reached its economic limits of production.
Ultimately, economic production or operating limits can be reached
on any well regardless of oil well depth and location, but certain
specific advantages are apparent for stripper orphaned wells that
might be capable of producing less than ten barrels of oil per
day.
[0019] It would be desirable, therefore, to provide a continuous
loop pump technology capable of efficiently operating in
conjunction with orphan oil and gas well production in a manner
that makes production from such wells a cost effective endeavor. It
would be desirable to provide an efficiently operating continuous
loop pump system that, by way of both an efficient and optimized
structure and an automated and efficient operational control
system, could result in cost effective production from orphaned oil
and gas wells.
SUMMARY OF THE INVENTION
[0020] The present invention initially therefore provides a number
of improvements to the surface equipment components of a continuous
loop or rope pump production device. These improvements are
optimally incorporated into the operational components associated
with the system and correspond with specific control systems
designed to optimize system functionality. The present invention,
however, finds further efficiency in system automation,
diagnostics, and reporting. By applying certain key technologies
associated with system automation and control, the present
invention provides a continuous loop pump operational system that
includes diagnostics and reporting, production recording and
reporting, safety monitoring and maintenance, power monitoring and
backup, and energy efficiency. The cost effective pumping
mechanisms described in the present invention overcome many of the
problems associated with the removal of multiviscosity fluids and
gases, as well as the problems associated with variable well depths
and casing conditions. The combination of these improvements to
both structure and operational control result in a commercially
effective product that is capable of operating at a profit even
within an orphaned well environment.
[0021] The various improvements included in the present invention
may generally be categorized into four areas. These include: [0022]
(A) A loop pump sheave-pulley configuration and arrangement that
can be easily modified and adapted to a range of oil field
environments; [0023] (B) A complete local and remote monitoring and
reporting system for efficient operation and maximum production
performance; [0024] (C) An automated pump activation/deactivation
process and an automated production transfer (and reporting)
process; and [0025] (D) An improved safety system for the
containment, capture, and processing of well head gases and liquid
products.
[0026] It is therefore an object of the present invention to
provide improvements to prior art endless loop pump technologies by
introducing of information technology and performance reporting
through onsite and remote communication systems. Remote
communication is utilized to exchange data, such as alarm condition
reporting, production volume delivered, and remote modification of
extraction and delivery parameters in order to optimize the
operation of the continuous loop pump system. A further objective
is to reduce the need for onsite oil field personnel at a stripper
well production system in an effort to reduce the labor costs
associated with operation of the system. Further objectives and
advantages will be readily apparent to those skilled in the art
from the following description with reference to the appended
drawings.
BRIEF DESCRIPTION OF THE DRAWINGS
[0027] FIG. 1 is a top level schematic block diagram showing the
functional relationships between the primary components of the
system of the present invention.
[0028] FIG. 2 is a detailed schematic block diagram of the complete
system of the present invention disclosing both control module
components and mechanical/operational components.
[0029] FIG. 3 is a schematic, partial cutaway, side plan view of
the continuous loop pump components of the system of the present
invention.
[0030] FIG. 4 is a schematic, top plan view of the continuous loop
pump components of the system of the present invention.
[0031] FIG. 5 is a schematic, partial cutaway, end plan view of the
continuous loop pump components of the system of the present
invention.
[0032] FIGS. 6A & 6B are flowcharts of the methodology
associated with initialization of the system of the present
invention.
[0033] FIG. 7 is a flowchart of the methodology associated with
normal operation and status monitoring of the system of the present
invention.
[0034] FIG. 8 is a flowchart of the methodology associated with
operation of the fluid transfer system of the present
invention.
[0035] FIGS. 9A-9C are flowcharts of the methodology associated
with operation of the wellhead gas collection system of the present
invention.
[0036] FIG. 10 is a flowchart of the methodology associated with
operation of the alarm system of the present invention.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0037] As an oil well's production rate declines over time, it
reaches a point where it becomes economically unviable to continue
producing with the typical primary oil production equipment. Such a
low production well is commonly known as a "stripper well". In
order to continue viable economic production on such a well, an
endless loop pump type system can replace the typical oil
production equipment so as to reduce the energy required to extract
petroleum products from the well. This type of pump (an endless
loop pump) is relatively inexpensive to operate as compared to
typical oil production equipment. As indicated above, the present
invention seeks to reduce the cost of operation for such continuous
loop pump systems even further by efficiently controlling the
operation of the system and reducing the need for interaction by
oil field personnel.
[0038] An overview of the primary components of the system of the
present invention is disclosed in FIG. 1. The relationship of these
components also alludes to the methodology associated with the
operation of the system, which methodology is equally important in
making the system cost effective for the types of wells involved.
The petroleum extraction system 10 of the present invention (as
shown in block diagram form in FIG. 1) is comprised of a number of
interacting modules that work together to automate the process of
retrieving oil from a low producing well. Main control module 12
manages the process and methodology of the system by automating
most of those tasks that were previously performed by onsite oil
field personnel. Specific components within main control module 12
perform the routine management tasks required to drive efficient
operation of the system.
[0039] Main control module 12 is directly linked to a number of
specific applications modules. Loop pump control module 16
comprises those control components directly associated with the
operation of the hardware of loop pump system 28. Well head gas
recording and control module 18 comprises those components of the
control system directly responsible for operation of the gas flow
system 32 of the present invention. Likewise, fluid level recording
and control module 20 is directly responsible for operation of the
transfer pump system 30 of the present invention. Communications
module 22 is specifically responsible for communicating (both
transmitting and receiving) data and instructions between the main
control module 12 and a remote control center, relating to the
operation of the various components and modules within the system.
Finally, alarm control module 14 is under the direct control of
main control module 12 in a manner that provides both onsite and
offsite alarm indicators, as well as safety shut-down and operation
control mechanisms within the system of the present invention.
[0040] Reference is now made to FIG. 2 for a more detailed view of
the complete system of the present invention, including the
hardware components and the control module components mentioned
briefly above. The complete system shown in FIG. 2 may generally be
divided into two sections designated in dotted outline form as the
control system 10 and the pump operational system 8. The control
system 10 shown in FIG. 2 is essentially the same as that
structured more generically in FIG. 1. Controller/microprocessor 12
(the equivalent of main control module 12 in FIG. 1) operates by
way of direct control over a number of application control modules
associated with various components in the system of the present
invention. Alarm module 14, loop pump control module 16, gas
control module 18, liquid level control module 20, and
communications module 22, all carry out both control commands and
data acquisition functions in the operation of the system of the
present invention.
[0041] Loop pump system 8, on the other hand, comprises the various
hardware components associated with the overall pump system.
Primary among these components is loop pump 28 (described in
greater detail below) which is essentially made up of a continuous
loop rope member, along with the assembly of pulleys and guides
associated with driving the continuous loop member into and up from
the well. Loop pump 28 is under the direct control of loop pump
control module 16 and may, in certain embodiments of the present
invention, provide feedback data to loop pump control module 16
such as in the form of torque readings or current readings from the
electric motor in the system. Loop pump 28 is likewise connected to
alarm module 14 and provides similar feedback data on its operation
for the purpose of triggering an alarm or, by way of
controller/microprocessor 12, altering the operation of the loop
pump system in some manner.
[0042] Loop pump 28 draws production from stripper well 90 in a
manner described in more detail below. The produced fluids and
gases are directed to either liquid hydrocarbon reservoir 38 or
well head gas reservoir 40. In the preferred embodiment, these
reservoirs 38 and 40 may be integrated into a single containment
system, again as described in more detail below. Well head gas
reservoir 40 incorporates a gas pressure gauge 44, which provides
feedback to gas flow control module 18 in the controller system 10.
The gas pressure measurements are utilized to control the operation
of control valve 52, again directly linked to gas flow control
module 18. In addition, gas flow measurement is achieved at flow
meter 54, also providing feedback to gas flow control module 18. A
safety check valve 56 is provided in line with the output from well
head gas reservoir 40 that assures a unidirectional flow of well
head gas to natural gas gathering system 62 at a local or remote
location.
[0043] The liquid hydrocarbons removed from stripper well 90 by way
of loop pump 28 are directed to liquid hydrocarbon reservoir 38.
Within this reservoir, level sensor 42 provides feedback to liquid
level control module 20 within the controller system 10.
Information provided by level sensor 42 is utilized by the
controller system 10 to operate level controlled liquid valve 46 to
permit the flow of liquid hydrocarbons from reservoir 38 by way of
a transfer pump 64 (or other flow means) through to local or remote
liquid hydrocarbon gathering tanks (tank farm) 60. In this flow
conduit, liquid flow is monitored by flow meter 48. Unidirectional
flow within this conduit system is maintained by check valve 50 as
shown in FIG. 2.
[0044] Alarm module 14 is shown in FIG. 2 connected with a local
alarm system 26 (as an output device) and (by way of
controller/microprocessor 12, communication module 22, and remote
link 24) with a remote alarm system. Input to the alarm module 14
may be provided by a number of different components within the
system of the present invention. Examples of this are shown in FIG.
2 with connection to an intrusion detection sensor 66 positioned
within an enclosure surrounding continuous loop pump system 8 as
shown. Additionally, as mentioned above, alarm module 14 may
receive feedback sensor information from loop pump 28 itself
related to current flow or torque on the motor associated with
operation of the loop pump. Finally, as mentioned above,
communication module 22 operates in conjunction with
controller/microprocessor 12 to direct both data and instructional
signals to and from remote link 24 in both a periodic manner and in
an event driven manner.
[0045] The continuous loop pump system of the present invention,
when coupled with the indicated automation, control, and
information technologies, provides a means to decrease the capital
expense required, and significantly improve the operating
efficiencies, for the stripper well producer utilizing the system.
Continuous loop pumping technology is relatively simple in both
design and function and is therefore very efficient to operate and
inexpensive to manufacture. The operation of the system is
relatively dependable as well, requiring less maintenance and
repair than most other petroleum pumping systems. A continuous loop
pumping system essentially replaces all of the existing surface and
downhole pumping equipment at costs that are, on average, less than
10%-20% of an operator's initial capital cost associated with a
primary well pumping system. In addition, the selected use of
information and operating technologies as described herein can be
employed to reduce operating costs and significantly improve
capital utilization in the areas of: (a) overall capital
expenditures; (b) annual operating expenditures; (c) onsite
personnel expenses; (d) overall improved performance and reporting
procedures; and (e) automated system operation and procedures.
[0046] The technology implemented by the present invention and
described generally in FIG. 2 represents a number of significant
improvements to the typical surface equipment portion of the
continuous loop pump system. These improvements are incorporated at
the operating unit of the system and enhance the effectiveness,
safety, and operating efficiencies of the overall process. These
improvements generally include: [0047] (A) A flexible sheave/pulley
arrangement that allows utilization of the system at varying depths
and with varying types of fluid that would normally require
multiple drive configurations. The drive pulley configurations of
the present system can be easily customized for the task of
improving torque, depth, fluid recovery from the formation, etc.,
all while keeping manufacturing costs low and the overall process
simple and efficient. [0048] (B) Complete local and remote system
monitoring and reporting components for the efficient operation and
maximum production performance. These monitoring, control, and
reporting components include an automated system sequencing and
operation control component; periodic production reporting; system
status and fault reporting; motor operational start up and shut
down and reporting; auto failure shut down and reporting; wireless
communications for total system integration and non-landline
connectivity to a remote main office; onsite system access and
reporting; intrusion protection and reporting; and remote video
access and recording. [0049] (C) Components for the automated
control of production rates production transfer, and reporting to
storage facilities (tank farm or tank battery). This is
accomplished by an onboard intermediate storage tank for production
reporting; precise single barrel (or fractional) fluid transfer,
overflow alert and reporting triggers; transfer pump failure
reporting; and fluid check valve to prevent backflow from the tank
battery. [0050] (D) An improved safety system for the containment,
capture, and processing of well head gases. This is accomplished by
way of internal vessel pressure recording with a relief valve
system; an operational control valve and/or a pump for the transfer
of gases into a gathering system; and a check valve for backflow
protection.
[0051] Reference is now made to FIGS. 3, 4, and 5 for a more
detailed description of the structures and functions of the
continuous loop pump hardware system of the present invention. FIG.
3 discloses, in schematic detail, the primary components of the
continuous loop pump system. FIGS. 4 and 5 provide top and end
views of the system, primarily for clarification of the manner in
which the continuous loop member is directed around and about the
plurality of pulleys and drive wheels.
[0052] The flexible sheave and pulley arrangement components shown
and described herein provide an extremely flexible platform to
produce a cost effective pumping mechanism capable of meeting the
various demands and characteristics of well depth, torque, and
fluid viscosity. By providing multiple drive arrangements,
placements, and configurations, the operator may customize the
overall drive assembly to meet the specific pumping requirements,
and in turn reduce the complexity, maintenance, and cost of the
system. By providing improved separation between the drive sheaves,
the recovered fluids can be more effectively stripped and removed
from the continuous medium by way of wiper mechanisms.
[0053] While continuous loop pump technology shows promise for low
viscosity fluids, utilizing a high speed loop rotation, its true
effectiveness can be found in applications involving relatively
high viscosity, low volume fluid such as stripper oil well
production. The multidrive pulley and the variable configuration
provide an extremely flexible arrangement for moving the loop about
the well bore down into the fluid reservoir and back into the
producing unit for capture, regardless of the depth, fluid type,
straightness, or condition of the casing or well bore. The entire
assembly is formed with sealed covers attached to the pulley frame
and storage vessel, leaving the electronic and electromechanical
components in separate compartments from the pumping and recovery
assembly. The entire unit can be placed covering the well head
attached to or supported by a variable length leg assembly and does
not require any special hoist or overhead operations to service or
replace the unit.
[0054] As mentioned above, a further objective of the present
invention is to incorporate an automated transfer process whereby
produced fluids are systematically transferred to a main storage
facility (a tank battery or tank farm) in exact measured amounts in
order to keep track of individual well production quantities and
histories. In addition, the system of the present invention is
capable of sensing and reporting when transfer pumps have failed,
or delivery lines have become blocked and/or produced fluids are
returning back into the well bore or reservoir via overflow ports
in the internal storage tank.
[0055] A further objective of the present invention (as described
above) is to improve the safety and recoverability of formation and
solution gases (commonly referred to as casing or well head gases)
from the reservoir. The sealed pumping environment of the present
invention employs pressure measurement devices (a pressure gauge)
and pressure release valves to alert and protect personnel from
potential hazardous conditions prior to opening and servicing the
pumping unit. In addition, small gas pumping units or compressors
with check valves may be installed to take advantage of the
marketability of well head gas, and in turn, insure that the gas is
removed from the unit and pumped into the main gathering area for
pipeline sale.
[0056] Reference is now made to FIG. 3 for a brief description of
the primary components of the hardware system of the present
invention. FIG. 3 is a schematic, partial cutaway, side plan view
of loop pump system 8, including both the surface components and
the down hole components of the system. Loop pump system 8 is
comprised of a series of pulleys that include drive pulley 72, take
up pulley 73, and guide pulleys 74 and 76. In addition, a down hole
weighted pulley assembly comprising lower pulley 78b and upper
pulley 78a is positioned within liquid petroleum product 92
contained within well bore 90. An endless loop member 80 extends
around each of the pulleys mentioned above and into well bore 90
where a loop of the flexible rope-like material is established
within the liquid petroleum product 92 by the weight of down hole
pulleys 78a and 78b. Endless loop member 80 is comprised of any of
a number of types of materials (discussed in more detail below)
such as hydrophobic rope, cable, or chain that dips into well bore
90 and the formation therein to collect the petroleum liquid 92
from below the surface within the petroleum reservoir and to
thereby carry it to the surface for retrieval. The liquid is
collected at the surface in collection reservoir 38 in a manner
described in more detail below. Enclosure 40 covers the system both
preventing the contamination of the liquid and allowing the
collection of casing wellhead gases, again as described in more
detail below.
[0057] Loop pump system 8 of the present invention may be
positioned on the surface in direct connection with casing
components for well bore 90. The cabinet that defines collection
reservoir 38 and enclosure 40 may be constructed in a generally
rectangular box-like configuration supported on the ground surface
by adjustable legs 87 as shown. The well head casing should be in
place to extend from well bore 90 to a height at least above a
level within collection reservoir 38 as to prevent the immediate
return of collected fluids into well bore 90. A conduit is
positioned for controlled connection to liquid hydrocarbon
gathering system 60 at an appropriate placement on collection
reservoir 38. In a similar manner a conduit is positioned for
controlled connection to natural gas gathering system 62 in
association with enclosure 40 for the collection of wellhead
gases.
[0058] The arrangement of pulleys associated with the loop pump
system 8 of the present invention may generally be described as
follows. Endless loop member 80 passes up out of well bore 90 over
guide pulley 74 and then across and above collection reservoir 38
to take up pulley 73. As shown in more detail in FIGS. 4 and 5,
take up pulley 73 may comprise multiple pulley channels to
facilitate the repeated looping of endless loop member 80 between
take up pulley 73 and drive pulley 72. After looping a number of
times between these pulleys, endless loop member 80 passes through
a wiper 77 before crossing over guide pulley 76 and returning into
bore hole 90. Within bore hole 90, at a level appropriate for
absorbing liquid petroleum product, endless loop member 80 extends
in a single loop around a down hole weighted pulley assembly. This
assembly, as mentioned above comprises a pair of pulleys 78a and
78b that are joined in the manner shown to provide an assembly of
sufficient weight to maintain the assembly within the fluid
reservoir and to facilitate the prevention of twisting as may occur
with use of a single weighted pulley. Under the influence of drive
pulley 72, the closed loop member 80 follows the circuitous route
described above. Between the guide pulley 74 and the subsequent
pass over guide pulley 76 the liquid petroleum is squeezed, drained
from, or otherwise removed from the endless loop member 80 and is
collected within collection reservoir 38.
[0059] FIG. 4 provides a top plan view of loop pump system 8
showing the offset positions of guide pulleys 74 and 76 and the
manner in which they guide endless loop member 80 into and out from
bore hole 90. Support panel 79 is shown to provide the necessary
(variable) spacing and placement for the support axles of each of
the pulleys described above. Positioned below the level of take up
pulley 73 is electric drive motor 28 shown positioned for
attachment to drive pulley 72. The manner in which this connection
is made is shown better in FIG. 5, described in more detail below.
Control instrumentation 10 may, in one embodiment of the present
invention, be positioned behind panel 79 in a manner apart from
both fluid collection reservoir 38 and gas collection enclosure 40.
Electric motor 28 is likewise separated from these two fluid and
gas enclosures.
[0060] FIG. 5 shows in greater detail the manner in which take up
pulley 73 and drive pulley 72 serve to create a plurality of loops
from which the liquid petroleum product may drain into collection
reservoir 38. Those skilled in the art will recognize that
variations in the number of loops between pulleys 73 and 72 may
accommodate different types of endless loop members and different
viscosities of hydrocarbon products.
[0061] Other variations to the structure of loop pump system 8 are
anticipated that facilitate the pumping of different types of
hydrocarbon fluids and different mixtures of such fluids. It is
anticipated, for example, that the various pulleys described above
may be positioned in different locations on panel 79 (FIG. 4) in
order to provide different angles and different lengths of exposed
sections of endless loop member 80 to optimize the removal of
petroleum fluids from endless loop member 80. Although the basic
pulleys described and their placement are considered part of the
present invention, the size, position, and loop segments for each
of these pulleys may vary according to the specific hydrocarbon
characteristics. In general, however, the structures described
above and shown in conjunction with FIGS. 3-5 are such as to
operate most efficiently with the methodologies of the present
invention described in more detail below. As one of the objectives
of the present invention is a system that requires relatively low
cost installation to carry out the production of hydrocarbon fluids
from low production wells, the systems and structures shown in
FIGS. 3-5 are geared toward simplicity and efficiency.
[0062] The methods associated with implementation of the systems of
the present invention follow directly from the control components
described above and the related hardware associated with these
components. One of the primary benefits of the present invention is
the automated control of systems that would normally require the
attention of onsite personnel to both operate and monitor. The
control systems of the present invention serve to both gather data
regarding the operation of the system and to control that operation
based upon the character of the data gathered. In general, the
operation of the system of the present invention can be
characterized as involving one of five different areas of control.
These include: (a) initialization; (b) pump operation and
monitoring; (c) transfer operation and monitoring; (d) data
communication; and (e) controlled shut down. The specific steps in
the methodologies associated with each of these aspects of the
control function are described in detail below. A brief summary of
each is provided first followed by step by step descriptions of a
preferred embodiment of each.
[0063] Initializing the system (see FIG. 6) first involves powering
on the appropriate hardware components associated with the
continuous loop pump system machinery. Activation of power to the
system activates the sensors and controls (as described above) and
only after confirmation of a "no-alarm" condition is the loop pump
itself activated. Alarm system activation is therefore a primary
step in the initialization process for the overall system. In
addition to alarm activation, nominal signals from each of the
liquid measuring devices (level sensor and liquid flow sensor) as
well as the gas monitoring devices (gas pressure gauge and gas flow
meter) may be checked. The control system then establishes and
confirms the record keeping function for operation of the system
and identifies the date and time data associated with the
initialization of the system. Such data is derived from a
clock/calendar associated with the controller microprocessor of the
system.
[0064] The process of initializing the system may be manual, as for
example the first time the system is established at a particular
well site, or may be remotely triggered by a communications signal
from a central control center. The process of initializing the
system may also be based upon a timed function established in the
control system programming, again depending upon the specific well
conditions that the system is operating with. In any of these forms
of initialization there may be parameters associated with the
operation of the system that require verification at start up.
Therefore, once the program runtime has been established by
reference to the clock/calendar within the system, a confirmation
of the appropriateness of system start up is made. If the date/time
is outside of the program runtime established within the system, a
hold or stop command halts or delays the start up process until the
runtime is consistent with the programmed parameters.
[0065] If the operational runtime is confirmed as accurate, the
system proceeds to check the status of all of the various
components and sensors as described above. Initially, the reservoir
is checked to determine the liquid level status. If the reading is
low (within an appropriate start up range) the system proceeds to a
pump start operation. If the reading is high for any reason (an
anomaly at start up) the system is shut down and a report is
communicated to the remote location. With a reservoir level within
parameters, the system initiates the operation of the pump motor to
begin the extraction of fluid from the well.
[0066] During any operation of the pump motor, both current and
torque measurements are made on a constant or periodic basis. These
measurements determine the efficient operation of the pump, as well
as the safe operation of the system, and would alert the control
system components to any conditions that would require either shut
down or modification of the operation of the pump. On certain
conditions, such as extremely high current or extremely high
torque, a pump malfunction or jam may be determined, which would
prompt a complete shut down of the system (and send a report to the
remote location). Short of these extreme conditions, however, the
monitoring process operates to provide the information necessary
for the system to decide to alter the drive motor conditions in the
loop pump. High viscosity fluids, for example, may result in a
higher torque reading from the sensor associated with the loop pump
motor, which might prompt the system to direct the motor to operate
at lower speeds. Conversely, low viscosity fluids that would result
in a lower torque reading may allow the motor to operate at higher
speeds. Other variables associated with the torque and current
readings will have commensurate effects on the decision making
process programmed into the controller microprocessor that allow
for achieving optimal efficiency for a variety of fluid viscosities
and operating conditions.
[0067] As long as normal (within range) current and normal torque
readings are present, the operation of the pump motor continues
according to fixed parameters. The system constantly checks for a
high torque condition or a high current condition that might prompt
pump motor shut down (and a corresponding data communication
report) as well as low torque conditions that might indicate the
temporary exhaustion of fluid in a formation. While the system is
constantly checking the status of the pump motor, it begins to also
follow the fluid level condition and the gas pressure condition
within the respective reservoirs of the system. Data regarding
fluid level is received from the level sensor and communicated to
the control components of the system, specifically the liquid level
control module of the loop pump control system. The data record of
fluid levels provides not only the reference point for initiating a
transfer of fluid from the reservoir to a tank farm, but also
provides a measure of the rate at which fluid is being produced
from the well by the pump. This rate also has an effect on the
operation of the pump in combination with the torque measurements
and current measurements being made. All of these sensed
characteristics contribute to a decision as to the rate of
operation for the pump, as well as its periodic shut down and start
up.
[0068] A high fluid liquid level in the collection reservoir would
of course start the transfer process to deliver fluids from the
fluid reservoir to the liquid hydrocarbon gathering tanks located
at the onsite or remote tank farm. This process involves the start
up of the transfer pump as well as the opening of a control valve
connected to the fluid reservoir. Fluid flow measurements are then
made during this process with the liquid flow meter in the system.
Back flow from the separated tank is prevented by way of a check
valve in the same conduit lines. During the transfer process, a
record is made of the transfer date and time, and a report of the
same is communicated to the remote centralized location. Fluid
level within the reservoir continues to be monitored during the
transfer, and on reaching a low fluid level reading, results in the
shut down of the transfer pump and the closing of the respective
control valves.
[0069] Reference is now made to FIGS. 6-10 for a more specific
description of the methodology associated with the operational
control of the system of the present invention. As indicated above,
many novel aspects of the present invention relate to the manner in
which the hardware described is automatically controlled so as to
operate in an efficient and cost effective manner. Although the
hardware systems involved are relatively simple in configuration,
the control system of the present invention takes advantage of many
advances in automated technologies to make practical the
implementation of the system of the present invention.
[0070] Reference is made first to FIGS. 6A & 6B for a detailed
description of the initialization process associated with starting
up the system of the present invention. Initialization of the
control system begins at step 100 in FIG. 6A wherein either an
onsite operator or through a remote control signal communication,
the microprocessor system of the present invention is powered up
and programming started. A first important step in the
initialization process is shown at step 102 wherein the alarm
system is activated, the details of which are shown more clearly by
the link 104 to FIG. 10. Once the alarm system has been activated
at step 102 the process proceeds to acquire the current date and
time at step 106. This information is acquired from real time
date/time data at step 108. This is followed by the retrieval of
the programmed run times at step 110 in the system. Programmed run
time data 112 is pre-programmed timetable information instructing
the system when to operate and when to shut down. A number of
factors might affect the frequency of operation and the time of day
that the system is operated. As discussed above, certain formations
require a recovery period that will vary significantly depending
upon the structure and age of the formation. For this reason it is
important that the present system be programmable with respect to
both the duration of the cycle for pumping and the frequency with
which the cycle is repeated. Decision step 114 determines whether
the current date/time is within the programmed run times. If not,
then at step 116 the system waits (stops or pauses) for a period of
time before it again acquires the current date/time and determines
whether it is within the programmed run times.
[0071] If the current date/time is within the programmed run times,
then the system proceeds to step 118 wherein it retrieves the
programmed operational parameters. This programmed operational
parameter data 120 is likewise a pre-programmed set of information
that identifies the parameters for operation of the loop pump and
determines those conditions where certain actions are taken within
the system. These variable conditions include what volume of fluid
to transfer, what gas pressures to recognize as suitable for
transfer, what sensor readings indicate anomalies or errors in the
operation of the system, as well as various other types of critical
and non-critical data upon which decisions might be made during the
operation of the system.
[0072] At step 122 the system acquires the initial reservoir level
from reservoir level data 124. Decision step 126 then determines
whether the initial reservoir level is too high. If this is the
case, then at step 128 the system is shut down and an error is
reported. In general, whenever the system is instructed to "report"
an event, such will be transmitted by means of wireless
communication devices or the like to the central control facility.
If on the other hand the system is merely instructed to "record" an
event, such information may be stored in memory onsite for a later
download, or for a later wireless transmission with a batch of
data. If the initial reservoir level at step 126 is determined not
to be high, then the system is free to continue with pump motor
start up at step 130.
[0073] Now referencing FIG. 6B, and continuing from the
initialization routine shown in FIG. 6A the pump motor of the loop
pump is started at step 130. The system then acquires initial pump
motor torque and current at step 132 from pump motor torque and
current data 134. This provides this system with information
regarding the preliminary characteristics of the operation of the
pump motor. At step 136 the system determines whether a high torque
or high current reading is occurring. If so, then at step 138 the
system shuts down and reports an error on start up. If the torque
and current are within parameters, then the system proceeds to step
140 where it begins the system operation routine.
[0074] FIG. 7 capsulizes the broad methodology of the operation of
the system of the present invention. Beginning at step 142 the
operation proceeds from the initialization phase by beginning the
process of monitoring a number of variables within the system. Step
144 involves the monitoring of the fluid level in the reservoir
received from reservoir level data 146. The system carries out a
periodic or continuous recordation of the fluid level versus time
at step 148. A decision step 150 occurs with the monitoring of the
fluid level to determine whether the fluid level exceeds the upper
end of the set range. If so, the system proceeds at step 152 to the
process for fluid transfer. If the fluid level is not at or above
the upper parameter, the system proceeds at step 154 to monitor the
pump motor torque and current. This information is received from
pump motor torque and current data 156. The system determines
whether the torque and current are within pre-set parameters at
step 158. If not, the system proceeds at step 160 to shut down and
report the last measured parameters that caused the shutdown. If
the pump motor measurements are within parameters, the system
acquires the current date and time at step 162, again derived from
real time date/time data 164, and continues to determine at step
166 whether the date and time remain within the programmed run
times. If so, the cycle is repeated by returning to the operating
system start point 142. If the date/time are outside of the
programmed run times, then the system shuts down at step 168 and
reports a cycle completion.
[0075] Reference is now made to FIG. 8 for a detailed description
of the methodology associated with the process of transferring
fluid from the collection reservoir to a local or remote tank
battery or storage facility. The process of transferring fluid
begins at step 170 which derives from step 152 in the operational
routine shown in FIG. 7. Step 172 follows with the start up of the
transfer pump, typically by electrical means, activating an in-line
pump associated with the conduit extending from the collection
reservoir. During the process, the fluid level within the
collection reservoir is monitored at step 174 by way of reservoir
level data 176. If the fluid level is determined to be low (below a
shut off parameter value) at step 178, then the transfer is stopped
at step 180. If the level has not yet fallen to its low set point
as determined by the pre-set parameters, then the system continues
by a return to step 174 where operation of the transfer pump
continues and monitoring of the fluid level continues.
[0076] Once a quantity of fluid has been transferred from the
collection reservoir, and the transfer pump has stopped at step
180, the system acquires the current date and time at step 182,
again from real time date/time data 184. The system then records
and/or reports a transfer date and time and the volume of the
transfer at step 186. Once this recording and reporting has
occurred, the system returns at step 188 to the system operation
routine.
[0077] Reference is now made to FIGS. 9A-9C for a description of
the various methodologies associated with the monitoring of well
head gas in conjunction with the operation of the system of the
present invention. FIG. 9A is a high level flow chart showing the
monitoring that occurs and which, depending upon the values
measured, initiates one or more actions within the gas collection
system. At step 190 the gas monitoring is initiated (it is
anticipated that in the preferred embodiment gas monitoring begins
to occur as soon as the overall system is initiated) as described
above with respect to FIGS. 6A & 6B. During this process at
step 192 the system acquires the well head gas pressure from well
head gas sensor data 194. A determination is made at step 196 as to
whether the gas pressure is high with respect to the pre-set
parameters for the same. If the gas pressure is high, the system
proceeds at step 198 to the process of transferring the accumulated
gas from the system. This process (shown in FIG. 9B) is initiated
at step 208 wherein the system opens the gas transfer valve. The
system continues to monitor the well head gas pressure at step 210
deriving well head gas sensor data 212 as indicated. A
determination is made at step 214 as to whether the gas pressure
has reached a sufficiently low level as to properly terminate the
transfer of the gas. If not, the system cycles back through the
process of monitoring the gas pressure until it does fall below a
pre-set level wherein at step 216 the system closes the gas
transfer valve. At this point the system acquires the current date
and time at step 218 again from real time date/time data 220. Step
222 involves the recording and reporting of the transfer date time
and the volume of the gas transfer completed. Thereafter the system
returns to the process of gas monitoring at step 224.
[0078] Referring again to FIG. 9A, if the gas pressure is not high
as determined at step 196, the system carries out a determination
as to whether service personnel may be present within or near the
system at step 200. This information is derived from personnel
presence indicators 202 which may be placed at a number of
locations within the system or in the locale around the system.
This information may also be transmitted to the site in
anticipation of the arrival of service personnel such that the
accumulation of well head gases may be dispersed either through a
transfer or ventilation of the same in advance of personnel
arriving at the well head. In any event, a determination is made at
step 204 as to whether service personnel are present. If not, the
process returns to the initial gas monitoring step 190. If service
personnel are present, or are anticipated to be present, the system
proceeds at step 206 to the process of ventilating accumulated well
head gas. It should be noted that this step of ventilating gas only
occurs after a determination has been made that the gas pressure is
not yet high enough to merit the transfer of the gas to a remote
collection site as described above. The ventilation process is
intended to be a means for eliminating residual gas collected in
the system in order to provide a safe environment for service
personnel to work.
[0079] In FIG. 9C the process for ventilation is initiated at step
226 wherein the system opens the gas ventilation valve. During this
process the system continues to monitor the presence of service
personnel at step 228 derived again from personnel presence
indicators 230. A determination is made at step 232 as to whether
service personnel are present and, if so, the system cycles back
through the process until service personnel are no longer present.
Thereafter, at step 234 the system closes the gas ventilation valve
and proceeds at step 236 to acquire the current date/time, again
from real time date/time data 238, wherein at step 240 the system
proceeds to record and report the presence of personnel and the
ventilation of the well head gas. Finally, at step 242 the system
returns to the process of gas monitoring as shown in FIG. 9A.
[0080] Reference is finally made to FIG. 10 for a description of
the manner in which the alarm system of the present invention
operates. Alarm system routine 244 is initiated at the outset of
the start up of the overall control system of the present invention
(see FIG. 6A). The alarm system methodology primarily involves the
process of monitoring, at step 246, the plurality of parameters
that include reservoir fluid level, gas pressure, motor current,
motor torque, personnel presence, intrusion, power supply, and the
date/time. The alarm system identifies values for each of these
parameters and characterizes values that are outside of an
acceptable range as either meriting shut down or simply comprising
an anomalous condition that merits recording. At step 248 an
initial decision is made as to whether condition merits shut down
as being so far out of bounds as to create a safety hazard or to
indicate a serious malfunction in the hardware of the system. If
this is the case, then at step 250 the system shuts down and
reports the condition and the action taken. If the parameters are
not sufficiently out of bounds as to merit a shut down, the system
continues with a determination at step 252 whether an anomalous
condition still exists. If this is not the case, the system cycles
back through the monitoring process. If an anomalous condition does
exist, i.e., one or more of the measured parameters were determined
to be out of bounds, but not so significantly as to merit a shut
down, then at step 254 the system acquires the current date/time,
again from real time date/time data 256 and records the anomalous
condition at step 258. The process of recording anomalous data
allows service personnel to track performance over time and
alleviate or correct problems that might not instantaneously merit
shut down but which might degrade the efficiency of the system if
left uncorrected.
[0081] The above-described cycle of loop pump operation followed by
transfer pump operation is repeated according to the pre-programmed
regimen or operation for the system. Such a cycle might occur only
2 or 3 times a day, or, depending upon well conditions, may occur
repeatedly throughout a single day. During this process, well head
gas is being monitored in the gas reservoir of the system. The gas
pressure is an indication of the accumulation of well head gas
conducted away from the pump enclosure that directs the fluids into
the liquid hydrocarbon reservoir. In what is essentially a separate
monitoring system, gas pressure is maintained within certain
parameters by control valves that allow gas to flow from the
collection reservoir through conduits to a remote location where a
natural gas gathering system is in place. A gas flow meter in line
in this conduit maintains a record of the quantity of gas thus
directed to the remotely located gathering system. Here also, check
valves in the conduit prevent back flow of gas from the remote
gathering system into the well head gas reservoir. The collection
of well head gas is both a safety feature and a cost recovery
feature of the present system. Although operation of the system is
generally not dependent upon the collection of well head gas, the
occurrence of such is sufficiently common as to make its collection
an important part of the economic operation of the system of the
present invention.
[0082] Various mechanisms are in place within the control system of
the present invention to maintain its safe operation and to shut
down the system, either because of a safety concern, or during
normal periodic operational cycles. As indicated above, the alarm
module of the control components of the system of the present
invention are connected to both intrusion detection sensors within
the hardware of the system and to the loop pump itself as a manner
of monitoring the torque and current associated with operation of
the loop pump motor. The alarm module of the present invention also
receives control signals from the controller/microprocessor of the
control system that relate to other conditions within the system
that likewise would merit the triggering of an alarm. In general,
any non-programmed shut down of the system may merit an alarm
signal, both locally and at a remote location by way of a
communication transmission. The failure of, for example, a valve to
open upon a fluid transfer operation would first trigger a shut
down of the system, but then second may also merit the triggering
of an alarm condition.
[0083] In the preferred embodiment of the present invention, the
liquid level measurements being made would generally be used only
to trigger the operation of the transfer pump. However, under
certain conditions, a small change or no change in the level could
be a basis for shutting the continuous loop pump down for a
specified period of time. Certain formation characteristics may
require recovery such that initiating the operation of the system
after a 24 hour wait (or some other nominal time) could be
sufficient to allow the formation to recover and to thereafter
allow production to continue. In the preferred embodiment, the
collection tank and the transfer switch operation may be calibrated
to a specific fluid volume such as one barrel or one half barrel in
order to transfer such a specific amount of fluid at each
operation. This setting could be beneficial both for record keeping
purposes and cost effectiveness.
[0084] The above-described methods that involve varying the speed
of the continuous loop pump drive motor may be implemented to
address viscosity and potential well production conditions. Varying
the speed of the motor can be achieved through the use of a
variable speed motor, or through a gear assembly, both of which are
well known practices in the art.
[0085] An alternate embodiment for the fluid level sensor could
incorporate an ultrasonic measuring circuit to replace the standard
float switch assembly described above. This module would replace
the float switch for controlling the operation of the transfer
pump, and would also allow the monitoring of the rate at which
fluid comes into the on-board storage tank. The objective here is
to track the rate at which fluid comes into the tank, and when a
reduction of that rate is seen, a signal may be sent to the main
pump to shut down for some period of time in order to allow the
reservoir to recover by moving fluid into the well bore for
pumping. This sensing of the level is a more efficient approach
than simply controlling the time for operation of the main pump,
and thereby makes the entire process more efficient. Rather than
assuming formation recovery characteristics, the system can monitor
reservoir recovery and operate accordingly.
[0086] The composition and structure of the material associated
with use of the continuous loop rope itself may also be varied
according to the nature of the well and the viscosity and
composition of the fluid being drawn from the well. In the
preferred embodiment, the rope is a 5/8 inch to 3/4 inch hollow
braid polypropylene rope. The larger rope size allows for the
removal of a greater quantity of fluid from the borehole if
required, but at an added cost associated with the increased
weight. The 5/8 inch rope is an efficient compromise for wells that
produce less than 2 bbls a day. A further alternate embodiment for
the continuous loop rope involves placing a 1/4 inch cotton cord
inside a 3/4 inch hollow braid polypropylene rope in order to
effect water removal from the well in the process of operating the
pump. Some wells produce a great deal of water in proportion to the
amount of oil and require water removal in order to reduce the
hydrostatic head pressure on the reservoir.
[0087] Although the present invention has been described in terms
of the foregoing preferred embodiments, this description has been
provided by way of explanation only, and is not intended to be
construed as a limitation of the invention. Those skilled in the
art will recognize modifications of the present invention that
might accommodate specific oilfield and oil well environments and
structures. Those skilled in the art will further recognize
additional methods for modifying the composition and construction
of the continuous loop member to accommodate variations in fluid
viscosities and content. Such modifications, as to structure,
orientation, geometry, and even composition and construction
techniques, where such modifications are coincidental to the type
of oil field environment present, do not necessarily depart from
the spirit and scope of the invention.
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