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.

Description

BACKGROUND OF THE INVENTION

1. Field of the Invention

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.

2. Description of the Related Art

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.

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.

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.

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.

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.

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.

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:

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.

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.

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.

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.

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.

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.

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.

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.

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

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.

The various improvements included in the present invention may generally be categorized into four areas. These include:

• • (A) A loop pump sheave-pulley configuration and arrangement that can be easily modified and adapted to a range of oil field environments;
  • (B) A complete local and remote monitoring and reporting system for efficient operation and maximum production performance;
  • (C) An automated pump activation/deactivation process and an automated production transfer (and reporting) process; and
  • (D) An improved safety system for the containment, capture, and processing of well head gases and liquid products.

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

FIG. 1 is a top level schematic block diagram showing the functional relationships between the primary components of the system of the present invention.

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.

FIG. 3 is a schematic, partial cutaway, side plan view of the continuous loop pump components of the system of the present invention.

FIG. 4 is a schematic, top plan view of the continuous loop pump components of the system of the present invention.

FIG. 5 is a schematic, partial cutaway, end plan view of the continuous loop pump components of the system of the present invention.

FIGS. 6A & 6B are flowcharts of the methodology associated with initialization of the system of the present invention.

FIG. 7 is a flowchart of the methodology associated with normal operation and status monitoring of the system of the present invention.

FIG. 8 is a flowchart of the methodology associated with operation of the fluid transfer system of the present invention.

FIGS. 9A-9C are flowcharts of the methodology associated with operation of the wellhead gas collection system of the present invention.

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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:

• • (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.
  • (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.
  • (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.
  • (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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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 ⅝ inch to ¾ 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 ⅝ 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 ¼ inch cotton cord inside a ¾ 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.

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.

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.