HoSim is a flow network solver which can determine rate and pressure at a given point in a flow system based on terminal and inflow relationships.
An analytic model for fractured horizontal wells has been integrated in conjunction with inflow through perforations and different geometries in the horizontal completion. The fractured well model used is based on the premise that a boundary value problem may be conformally mapped onto a complex plane. The model divides each fracture and the wellbore into a number of flow divisions. Flow into a section is based on the length of each section and the associated pressure distribution. The model is pseudo steady state, but has the capability of being integrated with a gridded reservoir simulator the see the reservoir behavior which may include water or gas coning over time.
This paper gives the theoretical development as well as a North Sea field case simulation and results. The simulator is a new tool that gives the completion/reservoir engineer a way to better optimize single or multiple fractured horizontal well designs for maximum recovery.
Evaluation of multiple completion and stimulation alternatives has become more difficult in recent years due to the many options available on the market today. One of the most challenging scenarios for simulation is the multiple fractured horizontal well. The potential for enhanced recovery coupled with large completion and stimulation expenditures creates a need for better understanding of these complex flow environments. The model presented here attempts to model a system composed of a reservoir drainage block, multiple orthogonal fractures intercepting a horizontal wellbore, and a completion within that horizontal wellbore. This model is constructed using the concept of a flow network, where each component of the system is further subdivided into multiple flow divisions.
Description of the System
A horizontal wellbore is exists within a rectangular drainage block which has dimensions of axbxh. The wellbore azimuth is coincident with the local least principal stress direction within the drainage block. Hydraulic fractures which are introduced in this well will therefore lie in a plane orthogonal to the wellbore. It is assumed that induced fractures are spaced evenly along the length of the wellbore, making it possible to divide the drainage block into subsections, with one fracture lying within each block. These subsections are indexed as b1,b2,...,bn. Each fracture is assumed to be rectangular, having dimensions ci, Lfi, hfi. A diagram of this system is shown in Figure 1. This subdivision of the problem into multiple subproblems assumes that there is no flow between adjacent subdivisions. The size of the end blocks is adjusted to account for the effect of the 'greedy' end fractures, but this assumption requires that each fracture under consideration be given the same conductivity profile when discretized in the network model.
The lengths of the subdivisions of the drainage block can be derived based on the geometry of the system described above by assuming that each equally spaced fracture is geometrically centered in its drainage block, with the exception of the first and last fracture. It can then be stated that the length of the first and last block is given by,
Accurate Reservoir Evaluation from Borehole Imaging Techniques and Thin Bed analysis. Case Studies in Shaly Sands and Complex Lithologies in Lower Eocene Sands, Block III, Lake Maracaibo, Venezuela.
Computer aided signal processing in combination with different types of quantitative log evaluation techniques is very useful for predicting reservoir quality in complex lithologies and will help to increase the confidence level to complete and produce a reservoir. The Lower Eocene Sands in Block III are one of the largest reservoirs in Block III and has been producing light oil since 1960. Analysis of Borehole Images shows the reservoir heterogeneity by the presence of massive sands with very few shale laminations and thinly bedded sands with numerous laminations. The effect of these shales creates a low resistivity that has been interpreted in most of the cases as water bearing sands. A reduction in porosity due to diagenetic processes has produced a high resistivity behavior. The presence of bed boundaries and shales is detected by the microconductivity curves of the Borehole imaging Tool which also allows for estimation of the percentage of shale in these sands. Interactive computer aided analysis and various images processing techniques are used to aid in log interpretation for estimating formation properties. Integration between these results, core information and production data was used for evaluating producibility of the reservoirs and to predict reservoir quality. A new estimation of the net pay thickness using this new technique is presented with the consequent improvement in the expectation of additional recovery. This methodology was successfully applied in a case by case study showing consistency in the area.
The Lower Eocene Sands in Block III (Fig. 1) were discovered in 1962 by well VLC-363 in the eastern part of Lake Maracaibo. Early estimates suggest that 1.6 Billion stock tank barrels of oil were initially in place in the Lower Eocene Sands in Block III (Ref. 1).The initial recovery factor was calculated at 42 % and has produced 270 MMSTB while the remaining estimated reserves are calculated at 290 MMSTB. It was interpreted at the beginning of field exploitation that Lower Eocene sands were homogeneous (Ref. 1 ). Initially, the wells in the southern part had an average production of 4000 barrels per day of light oil. After ten years, the northern and eastern parts of the field where developed. These wells were troublesome, very costly and with very low production rates (Fig. 2). It became apparent that the reservoir was highly heterogeneous and complex. Production logging performed in some wells showed that only small intervals in the lithologic column were productive and that in some cases those intervals did not appear on standard logs as having the best potential. Any improvement in reservoir evaluation would require significative changes in the standard procedure followed for a normal homogeneous field. Effective reservoir characterization requires a successful integration of varied geological and petrophysical data that provides multiple benefits including increasing accuracy of reserves and well productivity estimates. Although high resolution well logging instruments have significantly contributed to improved reservoir description, the use of these increasingly remote and sophisticated methods makes it easy to forget that integration is the key to solving problems. High resolution electrical resistivity imaging is an important new tool in the field of petrophysics and is an important piece of information for core-log calibration. There are heterogeneous properties that can not be detected with a normal suite of log. These properties could control production of an interval due to restrictions in vertical flow through the sands. This paper describes how measured electrical images correlate with the porosity and permeability of the samples, and, in turn, with their petrographic characteristics.
Amoco Trinidad Oil Company has successfully field tested a non-rig isolation procedure to shut-off water encroachment in two of its gravel packed wells using a plastic resin plug. Amoco operates a gas production platform offshore southeast Trinidad with high volume gravel packed wells. High transmissibility of formation fluids in the completion near the wellbore usually makes it difficult to control unwanted water production. In the past. several techniques to control water have been attempted with varying degrees of success. These included setting plugs in the prepacked gravel screens or installing pre-designed hardware to plug off anticipated future water movement. These two techniques are usually unsuccessful because 1) the uncertainty in predicting reservoir performance and 2) the water bypasses any plugs in the screen assembly and flows through the high screen-casing annulus. Cement squeeze techniques work in medium to high pressure reservoirs but require rig assistance and potential damage to the completion may be sustained. The plastic resin technique uses dump bailers on slickline to place the resin across the desired interval which hardens and seals the flow area in the screens and effectively eliminates the permeability in the gravel thereby shutting off water flow from the reservoir. Because rig assistance is not required, this isolation procedure becomes more economical depending on the remaining gas reserves. Ultimate gas recovery is anticipated to be greater by having economical options available to pursue remaining reserves.
Amoco's Cassia field held the major reserves for supplying high pressure to satisfy our contractual obligations, Figure 1 shows the location of the Cassia field offshore. In 1983, production began and ended with nine wells draining four reservoirs. The '22' sand which had a significant amount of reserves remaining showed early signs of water production. The primary concern was that the reservoir would water out before the remaining reserves could be produced. Deliverability from this reservoir was 70 mmcfd, being supplied by Cassia #8 and #10. A structure map of the '22' sand can be seen as Figure 2. A shortfall situation in the supply of high pressure gas on the island was looming on the horizon. The problem at hand was how could we prolong the life of the 22 sand and maintain deliverability. The implications were enormous, there would be power outages throughout the country, plants at the Pt. Lisas industrial estate for example methanol, steel, urea and other plants being starved for gas and the resultant law suits for breach of contracts with the various parties involved. The method adopted to solve this problem had to be clinical, there was no room for error deliverability had to be maintained. One of the overriding constraints was that there was no rig readily available to repair the wells. The solution entailed attempting a water shut-off in one of these wells using a safe technique. After a lot of research, a resin plug was selected as the optimum solution.
Statement of Theory
The need to reduce water production is understandable in the oil industry. However it must be balanced with the need to maximize hydrocarbon production. Basically the opportunities for water reduction depend on how the water is moving through the reservoir and the barriers within the reservoir. Water movement can be sorted into various categories for example:
Thermal oil recovery was first started in Trinidad and Tobago in Palo Seco in 1966. The field started as a cyclic stimulation project but was later converted to a continuous steamflood in 1975. The project can be considered as one of the most successful thermal schemes in Trinidad and Tobago. The Palo Seco steamflood covers an area of 250 acres in the South Western region of the Island of Trinidad and Tobago. The reservoir being steamed, comprises three elements of the Lower Morne L'Enfer (LMLE) horizon, viz. D, E and F sands. Cumulative injection to date is 54.8 million barrels of steam with a cumulative oil production of 18.8 million STBO which is 38% of the original oil in place. The paper reviews the overall project performance of the steamflood. Predictions of the performance of new patterns are made using the Gooma steam model. The present economics of the project is discussed using the tolerable steam oil ratio approach.
The North Palo Seco Thermal Project (NPSTP) is situated in the North \Western section of the Palo Seco field, which is located in the Southern Basin of Trinidad (Figure 1).
This NPSTP is one of several on-going thermal projects being operated by Petrotrin. Oil production from these thermal projects is approximately 30% of Petrotrin's total land production, with the NPSTP contributing about 30% of thermal production and 8% of the total land production. After twenty (20) years of continuous steamflooding this mature steamflood now produces from twenty-five (25) patterns consisting of forty (40) injectors and one hundred and forty-five (145) off-takes covering an area of 250 acres (Figure 2).
The major contributing factors to the success of this project can be attributed to :- (a) The high reserves of shallow heavy oil (average 140 API oil). (b) A reliable constant supply of fresh water and natural gas for steam generation. (c) Reservoir continuity within the project limits. (d) The accumulated expertise gathered over the last 25 years from Petrotrin's predecessor companies. (e) An average oil sand thickness of 180 feet.
Other parameters of permeability, porosity, reservoir pressure depth, dip and oil viscosity are within acceptable limits when compared to some successful steamfloods - Refs. 1-6.
RESERVOIR DESCRIPTION FIELD DEVELOPMENT
For details of the field development and reservoir description refer to Reference 7.
Steam injection has been in the D, E and F sand units of the Lower Morne L'Enfer sand formation. The sand units, separated by shale breaks (5-10 ft) are at subsea depths ranging from 500 feet to 2000 feet with average nett and gross sand thicknesses of 180 and 335 feet respectively. Figure 3 shows the type-log while figures 4, 5 and 6 display the nett oil sand thicknesses of the D, E and F sand units. It should be noted that the "E" sands are the thickest and most well developed sands of the three units. The structure map for this thermal project was drawn on the Upper Coora Silt marker which separates the LMLE "E" and "F" sand units. The reservoir has a 200 sand dip to the southwest (Figure 7).
The history of the oil industry in Trinidad's land-based fields, reflects a domination by foreign multinationals initially, followed with ownership by various state-owned oil companies. Recently however, local entrepreneurs have been afforded the opportunity to participate to some extent, in oil production activities of the land-based operations of the state-owned oil company.
The state-owned oil company of Trinidad and Tobago has over five thousand (5000) inactive wells. Because of limited capital resources and the resultant low priority for reactivation, a programme of leasing blocks of these idle wells to small independent operators was initiated in July 1989. This programme is currently being expanded because of its initial success. In addition, acreages are being offered for farmout operations, again because of the scarcity of capital funds for internal investment and the associated risks involved.
As a consequence of these programmes, the oil production scenario in Trinidad's land-based operations is undergoing a radical transformation. This paper reviews the current status of lease operatorships and farmouts and discusses the key issues involved.
Trinidad is the most southerly of the Caribbean Islands and is located to the east of Venezuela (Figure 1). The major part of the history of the oil industry of Trinidad's land-based operations reflects a domination by foreign multinationals including Shell, Texaco and British Petroleum amongst other smaller foreign companies. Over the years, the land-based assets of these companies were acquired by the Government of Trinidad and Tobago to form two state-owned oil companies TRINTOC and TRINTOPEC. In 1993, these two companies were eventually merged into one state-owned oil company, PETROTRIN.
In the late 1980's, because of the low oil prices, many wells became uneconomic to produce and were left idle.
D. Mangalsingh, and T. Jagai, SPE
The CO2 immiscible process is a potentially viable method of EOR for local reservoirs. Although this type of flood is being conducted on a pilot scale in Trinidad, no laboratory work has been done to support this field effort. This paper presents the results of the first laboratory investigation of CO2 immiscible displacement of local crudes using both the continuous injection method and the water alternating gas method (WAG).
The continuous depletion of Trinidad's oil reserves necessitates the development and improvement of thermal and non thermal enhanced recovery techniques. Approximately 60% of the present oil reserves cannot be exploited because of present technical and economic constraints. The use of steam as a recovery agent loses it's economic viability when the reservoir is deeper than 1000m and when the formation is less than 10m thick. This is as a result of the heat loss associated with such conditions. The problem of poor areal and vertical sweep efficiency has limited the recovery in many heavy oil reservoirs. During the period 1920-1930 papers and patents were published indicating that carbon dioxide was a fluid capable of recovering oil from hydrocarbon reservoirs. In 1945 Poettman and Katz discussed the phase behaviour of CO2 and paraffin systems. Their studies indicated that a 10% to 20% increase in oil volume and a viscosity reduction too less than 0.1 of the original value was due to the solubility of the CO2 in the paraffin. The 1950's and 1960's saw emphasis in the application of CO2 as a miscible displacing fluid. At that time researchers understood the limitations of miscible CO2 flooding to be:
(1) High pressures that were required to achieve miscibility;
(2) Reservoir depths greater than 1000m;
(3) Crude oils of 30 API gravity and over gave high miscible pressures.
These restrictions prompted researchers to investigate the effectiveness of CO2 immiscible displacement for oil recovery. Four U.S. patents were issued to Martin et al, in 1959 relating to immiscible use of CO2 for oil recovery. The early 1970's saw field applications of immiscible CO2 which showed potential performance. The methods of CO2 injection were mainly continuous and huff and puff until the identification of WAG in the 1980's.
Continuous CO2 was deficient in areal sweep efficiency which resulted in early carbon dioxide breakthrough. Research also indicated that the production gas oil ratio (GOR) for continuous injection was very high. WAG injection resulted in lower mobility of carbon dioxide, thereby increasing sweep efficiency and lowering produced GOR. Rojas and Farouq Ali performed a scaled model study of carbon dioxide/brine injection strategies for heavy oil recovery from thin formations and disclosed the potential of WAG application.
CO2 immiscible displacement is a well established technique for increasing the recovery of crudes. This has been applied to reservoirs throughout the world. CO2 injection into Trinidad reservoirs started a few decades ago. Recovery as a result of this effort has been insignificant. Within the last few years, a more determined effort to implement CO2 immiscible displacement on a pilot scale has been attempted. However, no laboratory work has been conducted to support this field effort.
This paper describes the laboratory work that is being conducted to investigate the behaviour of local crudes when subjected to immiscible displacement by CO2 flooding. It presents the findings to date and compares them with those published. It also attempts to identify the important parameters that enhance recovery and seeks to optimize these parameters. The effect of continuous injection of CO2 on recovery has been studied. This has been compared to the recovery due to injecting alternate slugs of CO2 and water.
Immiscible CO2 flooding is a technique in which the flow properties of the oil in the reservoir are improved. The concept of immiscible CO2 flooding implies that CO2 is injected at subcritical pressures. In addition to providing energy to the reservoir, four mechanisms which contribute to increased oil recovery have been documented.
The perturbation method provides approximate solutions of the well pressure for arbitrarily heterogeneous media. Although theoretically limited to small permeability variations, this approach has proved to be very useful, providing qualitative understanding and valuable quantitative results for many applications. The solution is expressed by an integral equation where the permeability variations are weighted by a kernel, the permeability weighting function. As presented in previous papers, deriving such permeability weighting functions appears as a complicated calculation, available only for special cases. This paper presents a simple and general method to calculate the permeability weighting function. In the Laplace domain, the permeability weighting function is easily related to the pressure solution of the background problem. Since Laplace pressure solutions are known for many situations (various boundary conditions, stratified and composite media etc), the associated permeability weighting function can be immediately derived. Among other examples, we calculate and discuss the well pressure solution for a horizontal well producing from a heterogeneous reservoir.
The trend for reservoir characterization has stimulated the study of well testing in more complex heterogeneous media.
Well testing in heterogeneous media has been studied by three approaches: exact analytical solutions, numerical simulations and approximate analytical solutions. Exact analytical solutions exist for a restricted class of problems, involving some simple symmetry: layered reservoir, single linear discontinuities, radially composite systems etc. Rosa and Horner computed the exact solution in the case of an infinite homogeneous reservoir containing a single circular permeability discontinuity. Most of these analytical solutions are written in the Laplace domain. Numerical methods can treat much more general situations, but have some disadvantages: their use is cumbersome, investigation is empirical and general insights are difficult to be extracted, results are inaccurate if the time and the spatial discretization were not carefully conducted. Approximate analytical solutions can be a practical way to understand the pressure behavior in geometrically complex heterogeneous media. Kuchuk et al. proposed one of these approximate methods. Another popular class of approximate analytical solutions is based on the first-order approximation obtained from perturbation methods.
This paper is related to these first-order approximate solutions of the well pressure in arbitrarily heterogeneous reservoirs. In particular, we propose an easy and general method to calculate the permeability weighting function in various flow geometries. In the next section, we define what the permeability weighting function is and review previous works in the domain. After that, we present our method to calculate the weighting permeability functions. The technique is demonstrated in three situations, including the case of flow through a horizontal well.
The Permeability Weighting Function
The perturbation method is a well known technique to solve partial differential equations involving mathematical difficulties, like variable coefficients. According to this technique, we start from an easier problem, the background problem, to modify or perturb it. The full problem is approximated by the first few terms of a perturbation expansion, usually the first two terms.
In our context, we start from considering a background medium with permeability k0 and with specified boundary conditions. The permeability k0 may vary in the space, i.e k0 (xD) What is important is that the background problem has a known exact analytical solution, PDO (XD , tD).
The full problem has the same boundary conditions of the background problem but the permeability k(XD) differs from ko(XD) in arbitrary regions of the space. Rigorously speaking, k(XD) / k0 (XD) has to be close to 1 in order to obtain sound approximations. In practice, errors tend to be small, say less than 10%, even for relatively greater contrasts, say up to 10, between these permeabilities, depending on the specific problem.
The natural gas industry of Trinidad and Tobago is separated into the upstream gas producers and the downstream which includes the direct gas based industries and the gas transmission company. Past financial data was collected for both the upstream and the downstream. A detailed computer model was constructed and by its use financial projections were extended for this paper to the year 2015, for both the upstream and downstream. The significance of the installation of a world-scale liquefied natural gas plant on Government revenue is also discussed. The paper presents relationships found over the period between gas price, profit and taxes and attempts to analyze these relationships. Sensitivities are done to determine the effect of several factors on the gas producers profitability.
The paper estimates the total revenue benefits to the Government of Trinidad and Tobago, in particular those derived from the LNG plant and concludes that the timing and size of all escalation factors on gas prices, both upstream and downstream, should be kept under constant review.
Natural gas in Trinidad and Tobago occurs under three categories :- as dry gas reservoirs such as those off the North Coast; as wet gas in gas condensate reservoirs such as those in the Teak, Cassia and Kiskidee Fields in the East Coast marine area; and as dissolved gas in the crude oil and produced as "associated gas" during oil producing operations.
The gas is of very high quality, containing over 92% methane and negligible hydrogen sulphide and is therefore considered a sweet gas. It is estimated that the proven non-associated natural gas reserves are in the order of 8.7 (TCF) trillion cubic feet of which 70% belong to the East Coast marine area. At the present rate of production, the expected life of the gas reserves are in the order of 45 years.
The major gas fields of Trinidad and Tobago and main gas lines are shown in Figure 1. At present, the main supplier of high pressure natural gas is Amoco Trinidad Oil Company from its offshore wells in the Teak, Cassia, Immortelle and Flamboyant fields located off the East Coast of Trinidad. Other suppliers include Enron Gas and Oil Limited and Trintomar.
The National Gas Company of Trinidad and Tobago Limited (NGC) owns and operates two (2) offshore platform for compressing "low pressure associated gas". This company purchases and sells natural gas, and transports and distributes it to several consumers throughout the country. NGC's responsibilities include ensuring security of natural gas supplies to downstream consumers, pricing of natural gas, investigating the feasibility of gas related projects, and the implementation of such projects.
Natural gas from the fields offshore is transported via a 24 inch and a 30 inch line to the Phoenix Park Gas Processors Limited (PPGPL) plant at Point Lisas, where the heavier gases mainly propane and butane are extracted for exportation, while the natural gasolines are utilized in Petrotrin's refining operations. The methane rich gas is then distributed to various consumers across the country where it is used as a feed stock in the petrochemical industry, as fuel for power generation and in heavy and light manufacturing industries. Natural gas supply and utilization charts are shown in Figure 2. P. 729
With the increased drilling of highly deviated wells in regions of high temperature and pressure, frequently crossing weak formations, a perfect adjustment between the parameters of the drilling fluids and of the primary cementing slurries becomes imperative. With this aim, and using as a guide the success factors determined from the analysis of successful and unsuccessful primary cementing operations performed in the Campos Basin, offshore Brazil, tests were conducted in a physical simulator of downhole conditions to document the quality of zone isolations obtained with variation of the rheological parameters of the drilling fluids, the primary cement slurries, the inclination and caliper of the well, the casing eccentricity and the annular displacement velocity. In parallel, starting from accurate determinations of the rheological behavior of the cement slurries and drilling fluids and from the casing eccentricity, the velocity profiles in the annulus were determined from theoretical models. The shape of these profiles was one of the parameters used to justify the success or failure of the simulated cementing job. A three parameter rheological model was used.
Finally, based on success factors determined from data base analysis and from experimental validation of the theoretical model used for designing velocity profiles, general directives were established for the rheological parameters of the fluids to be used before and during cementing, for the shape of the velocity profile, as well as for the optimal annular velocity range, in order to guarantee the flow of the slurry to all parts of an eccentric annulus and thus to achieve an excellent success ratio for primary cementing operations.
Activities in the Brazilian petroleum industry have lead to drilling under ever-more-challenging conditions, characterized by locations in remote areas, depleted reservoirs, high temperature and pressure fields and water depths as great as 2000 m.
For the exploitation of these fields to be viable, it became necessary not only to significantly reduce the costs of the wells, but to refine the conventional drilling and completion procedures and to introduce of new techniques whenever necessary. This refinement aims at minimizing the operational risks which could prevent the continuation of the well or reduce its productive life. Following a worldwide trend, one of the strategies adopted to reduce the risks inherent in oil exploration in hostile conditions has been that of drilling more highly deviated and horizontal wells.
Highly deviated wells, drilled under high temperature conditions, mean that the formulations of the drilling muds and cement slurries must be much more complex than those used in vertical wells, to minimize the formation of a solid bed formed of cuttings which have fallen out of the drilling fluids and to minimize the early setting of the cement due to the loss of stability of the slurry. Such formulations make it much more difficult to adapt other physical properties of the drilling fluids and cement slurries to these two operational requirements with a view of making possible the complete substitution of the first fluid by the second and thus increase the chance of successful cementing operation of the annulus. Another difficulty is the risk of chemical incompatibility between the drilling fluid and the cement slurry. It is therefore desirable to minimize the area of contact between the two during the displacement.
Highly deviated wells, crossing zones with low fracture gradients, require fine adjustments to be made to the annular pressure during drilling, well conditioning and cementing, in order to avoid causing mechanical damage to the hole walls, which would cause undesirable washouts, which in turn would greatly increase the chance of not obtaining satisfactory zone isolation.
As can be seen, the optimization of the hydraulic design of the fluids used in the cementing operations is imperative to the obtention of high-quality sealing of well annuli, especially those which are highly deviated, where there are many other competing factors. Generally, when insufficient attention is given at this stage, the results shown by the acoustic logs are poor and successive corrections are required across the productive intervals. It should also be noted that if the well has a high temperature, as well as being deviated, the chances of sticking the string when squeeze cementing are high and should be considered among the risk factors which could cause the loss of the well.
This paper was written with the aim of maximizing the chances of getting successful cementing operations of highly deviated and horizontal wells, using as a basis the success factors obtained by Silva from an analysis of the data from successful and unsuccessful cementing operations in the Campos Basin.
The development of accurate digital measurement of instantaneous powerduring a pump stroke has made possible a very quick and detailed analysis ofthe efficiency of the pumping system. The efficiency is then used as thebenchmark for determining whether a complete well performance analysis iswarranted from the standpoint of making best use of personnel and economicresources to increase oil production.
In addition, power measurement provides direct information about liftingcost per barrel of fluid and barrel of oil produced, electrical and mechanicalloading of the prime mover, peak power demand, power factor and minimumrequired ratings. These results give operating personnel information regardingpotential problems and give to management a complete picture of thedistribution of pumping costs.
The power measurements are also converted, by the software, to instantaneoustorque and presented as continuous torque curves for the upstroke anddownstroke. This allows determination of the existing level of counterbalanceand provides the most rapid and accurate method for counterbalance adjustmentto achieve lower torque loading on the gear box and reduced energy utilization.One of the principal advantages of this balancing method is that counterbalanceadjustment can be made without need for an accurate description of the pumpingunit's geometry which is often unknown or inaccurate. The effect ofcounterweight displacement on torque and power is observed immediately byrepeating the power measurement after relocating the counterweights.
This paper presents a series of case studies showing the Application ofpower measurement to a variety of pumping systems and components, includingconventional, Mark II, Rotaflexunits and high efficiency motors.