It has been known that steamflood efficiency can be increased by adding surface active agents to steam such that foam can be generated, preferentially reduces permeability to steam in preferentially reduces permeability to steam in previously invaded zones, and diverts it through previously invaded zones, and diverts it through undepleted regions of the reservoir. In this study the partial results of a continuing project which aims to optimize surfactant use as additives in steamflood field applications are reported. Two steps of the project were completed up to date. As a first step, the foamability of seventeen surfactants was evaluated at steam injection conditions (160 degrees C and 75 psig) and linked to their chemical structure. As previously reported by D. C. Shallcross et. al., a linear model saturated with only water was used to compare and characterize different surfactants as steamflood additives. During the experiments surfactant solutions were injected as slugs into the sand pack after steam breakthrough. Nitrogen was injected as a non-condensible gas. The evaluation of foamability is based on pressure gradient changes and steam mobility reduction along the model. Under the conditions of the experiments, the alpha olefin sulfonates generated the strongest foam at low concentrations. Internal olefin sulfonates, linear toluene sulfonates and linear xylene sulfonates all generated stable foams at higher concentrations. Flow resistance due to foam also increased as the alkyl chain length increased.
In the second step, first the previous experiments were repeated by using eight selected surfactants to check if they were reproducible. During the runs two 10% PV slugs of surfactant solution with 0.5 weight percent concentration were injected into the sand pack. The second slug was injected after the foam created by the first one completely collapsed. Then these runs were repeated under the same operating conditions as the water runs except for the presence of oil. West Newport crude oil was used at residual saturation after steam flooding during these runs. The analysis of the results showed that both the pressure gradients and the reduction in steam pressure gradients and the reduction in steam mobility after surfactant solution injection were affected by the presence of oil. In the presence of oil no increase in pressure was observed to date.
The two sets of experiments were compared and discussed in detail using maximum pressure drops and duration of pressure changes, pressure increases with distance from the inlet and time, steam mobility reduction, and thermal parameters. One interesting result is the fact parameters. One interesting result is the fact that relative permeability to steam was reduced to between 0.005 and 0.02 when no oil was present. present
Steam injection is the most common method used in thermal oil recovery.
Sockeye Field, discovered in 1970, lies offshore California in the Santa Barbara Channel. The decision to develop the field was made in 1983 based on 1979-83 exploration drilling. Platform Gail was installed in 1987 and development drilling commenced in June 1988. Currently there are eleven development wells with plans for two more (two duals and eleven single completions).
This project has taken 20 years to reach the development stage since the lease sale in 1968. This long time span was partly due to permitting delays encountered in offshore California projects and a Santa Barbara Channel drilling moratorium in the 1970's.
The field produces from five reservoirs; Middle and Upper Sespe Sands, Lower and Upper Topanga Sands, and the Monterey Formation. Sespe Sands are fluvial channel deposits with individual sand bodies with limited areal extents. The Middle Sespe produces dry sweet gas and the Upper Sespe produces dry sweet gas and the Upper Sespe produces sweet 29 degrees API gravity oil. The produces sweet 29 degrees API gravity oil. The Topanga Sands were deposited in a near shore environment and are more continuous in nature. Lower Topanga Sands contain sweet oil whereas Upper Topanga Sands test a low gravity 18 degrees API sour oil. The Monterey Formation is composed of thin beds of cherts, porcellanites, siliceous shales, mudstones, and dolostones. The fractured Lower Monterey produces heavy sour oil, similar to that of the Upper Topanga.
To minimize risk, delineation wells were drilled early in the development program to ensure that reserves warranted additional investment in wells and facilities. Nine wells were completed during the first phase of the drilling program. Gas production from these wells was projected to exceed the capacity of the Carpinteria Gas Plant. The drilling rig was put on standby to evaluate various facilities modifications to handle production. At the conclusion of the evaluation, drilling was resumed with plans to drill four more wells.
Reservoir information was obtained through an integrated program of formation evaluation, core analysis, production logging and build-up and interference testing.
Sockeye Field is located about six miles north of Anacapa Island and nine miles west of Oxnard (Figure 1) on OCS leases 204,205,208 and 209. This paper describes the detailed history of the field from 1968 when these leases were acquired to the present development stage. Included are present development stage. Included are the exploratory drilling phases, the development drilling phases, the production response and the facilities constraints on production. The reservoir evaluation production. The reservoir evaluation program, which includes pressure testing, program, which includes pressure testing, production logging, rock and fluid analysis production logging, rock and fluid analysis and simulation, is also detailed.
The Sockeye structure is a broad NW-SE trending doubly plunging anticline. Maps 1 and 2 show the structure at the M4 marker and the Sespe unconformity.
An offshore polymer flood in the Dos Cuadras field near Santa Barbara, California was implemented early in 1986. The polymer selection process included laboratory screening and a month long field injectivity test with three prospective polymer suppliers. Polymer injectivity, required polymer concentrations Polymer injectivity, required polymer concentrations to meet design viscosities, the need for additional polymer inversion chemicals and core plugging polymer inversion chemicals and core plugging behavior of the polymer solution were critical parameters in this evaluation. Full-scale equipment parameters in this evaluation. Full-scale equipment design was aided by observing the performance of skids supplied by each vendor for polymer inversion and injection. Following the selection of a polymer product, shear tests were conducted to improve product, shear tests were conducted to improve polymer solution injectivity through Berea core polymer solution injectivity through Berea core plugs. Although these tests were sufficient to plugs. Although these tests were sufficient to ensure injection into the EP zone, additional shearing of the polymer solution was required to improve injectivity into the FP zone. A filtration test, which was found to be more sensitive than the core plug test to the plugging behavior of polymer solutions, was used to compare properties of injected solutions for the FP zone. Hall plots have been found to be useful for understanding the response of the injection wells to the various injectants.
Lease OCS P-0241 has three offshore platforms, "A", "B" and "C", which stand in 190 feet (58 meters) of water. Peripheral waterflooding began in 1971 into the EP and FP zones. Dual well completions are used for the injection wells with one string in each zone. The EP zone has a nominal surface injection pressure limitation of 200 psi (1380 kPa) at a depth pressure limitation of 200 psi (1380 kPa) at a depth of 1150 feet (350 meters) subsea while the FP zone has a nominal limitation of 400 psi (2760 kPa) at a depth of 1700 feet (520 meters) subsea. The average thickness of the EP and FP zones are 151 feet (46 meters) and 87 feet (27 meters), respectively.
Laboratory work showed the polymer flooding process could improve and accelerate oil recovery. The poor mobility ratio, low reservoir temperature and poor mobility ratio, low reservoir temperature and existing injection system were all favorable for polymer flooding. Conversely, the saline brine, polymer flooding. Conversely, the saline brine, the restricted wellhead pressure and the offshore location of the field were judged to be negative factors for implementing a polymer flood. Laboratory testing suggested that a three slug tapered design be used consisting of 5.5 cp, 3.5 cp and 2.2 cp (5.5 mPa s, 3.5 mPa s and 2.2 mPa s, respectively). Based on both laboratory data and the existing peripheral waterflood, a polymer slug size of 0.5 pore volume was selected.
Polymer selection for the offshore polymer flood Polymer selection for the offshore polymer flood was made by comparing three emulsion polyacrylamides during a 30-day injectivity test. All three polymers were chosen for field testing based on polymers were chosen for field testing based on laboratory studies. The chosen polymer was selected based on lower overall cost and ease of injection even though some samples failed the core plug test for injectivity. Polymer injectivity was a critical parameter because of the severe pressure limitations of the shallow reservoir. No additional chemicals were required to assist the inversion of the chosen polymer, as were needed for the other candidates. This feature requires one less pump per skid and substantially reduces the possibility per skid and substantially reduces the possibility of injecting uninverted polymer into the well, which can result in major formation damage.
Later studies showed the chosen polymer passed all core plug tests when mild shearing was performed on the concentrate stream prior to dilution.
As previously reported, a scaled physical model was developed to study the oil recovery efficiency of steam injection into horizontal wells. Experimental performance evaluations were made with two types of synthetic oils with injection of steam at different qualities. In this paper, the results of these laboratory studies are compared to predicted performance using a three-dimensional, three-phase thermal performance using a three-dimensional, three-phase thermal simulator.
Previously, most history matching studies have relied heavily Previously, most history matching studies have relied heavily upon adjustments to the relative permeability curves to obtain agreement between calculated and observed production data. In this study, to match production data we devised a new technique in which at elevated temperatures oil viscosity is lowered and water viscosity is increased so as to converge to a common value at steam temperature. Conceptually, this technique implies that at steam temperature oil and water tend to form as a combined emulsion phase. The presence of an emulsion phase is evidenced by experimental studies and thermal oil production in the field.
We successfully used the proposed technique to match the oil and water production data obtained from laboratory experiments. The efficacy of the technique demonstrated by comparing observations to three separate prediction runs; (1) base case using standard relative permeability and viscosity data (2) results computed with only relative permeability adjusted, and (3) results with only viscosity adjusted. The history matching studies include oil production from vertical wells in a five-spot pattern and horizontal wells in a trench pattern.
Steam stimulation and steam drives in reservoirs containing crudes with gravity 11 degrees API and higher have been very successful. However, economic recovery of heavier crudes, bitumens and tar sands, has still not been generally realm The concept of horizontal well technology for exploiting bitumen reservoirs offers exciting potential. Results are presented for two oils, one whose viscosity falls in the first presented for two oils, one whose viscosity falls in the first category and one in the latter.
The scaled physical model referred to this paper was constructed under a Small Business Incentive Grant from the Department of Energy to study the effectiveness of horizontal wells in recovering extra heavy oil. A 3-D thermal simulator called ASTRO (All Purpose Simulation of Thermal Recovery Operations) available at Union Oil Science and Technology Division was used to perform history matching studies of the experimental results. Both theoretical and experimental studies demonstrate the improved recovery gained from horizontal wells. Scaled physical models of the steamflooding processes are of great value in designing a steamflood and processes are of great value in designing a steamflood and obtaining insight into the process mechanics.
A three-dimensional thermal simulator is used for further studies of thermal processes. The purpose of the simulation study is to interpret the experimental results and confirm the suitability of a horizontal well for steamflooding.
An unique feature of this work is its effort to duplicate the results of a laboratory steam drive with a thermal recovery simulator. History matching is usually done by manually adjusting data through a trial-and-error procedure.
The use of surface calculated pressure buildup (SCPBU) tests has proven to be an accurate and cost effective technique for acquiring pressure transient data in the Kuparuk River Unit on the North Slope of Alaska. The technique involves measurement of the surface tubing pressure and use of a computerized acoustic device to measure the depth of the gas/liquid interface in the tubing of a shut-in production well. The bottom-hole pressure is then calculated by applying the gradients of the respective fluid columns. Conventional pressure transient analysis is then undertaken which provides useful information regarding provides useful information regarding reservoir and completion characteristics.
The equipment used was developed for performing SCPBU's in rod-pumped wells by performing SCPBU's in rod-pumped wells by monitoring the casing pressure and fluid level. However, with minor adaptations, it is successfully being employed at Kuparuk to measure the downhole pressure buildup via the tubing string of producing wells. To avoid the potential of natural gas accumulation in the wellhouses which protect wellheads in the arctic, the acoustic signals are generated by explosion signals from a nitrogen bottle secured in the wellhouse rather than through implosion to the atmosphere. As these acoustic signals are reflected by downhole jewelry such as gas lift mandrels (GLM), additional attention is required to ensure that the computer does not mistake a GLM for the fluid level as the fluid level rises or recedes in the tubing. This is currently being accomplished by frequent on-site monitoring of the fluid level's location in relation to downhole equipment, and adjustment of the "mute time" after which the computer will recognize an acoustic reflection as the true fluid level. After determining the measured depth to the FL, the computer then uses Input well deviation data to determine the true vertical height of the gas and liquid columns in the wellbore. The bottom-hole pressure is then calculated by applying the gradients of the respective fluid columns, with conventional pressure transient analysis techniques applied to the resulting pressure transient data.
It should be noted that using the subject technique presents an additional unknown in many pressure transient calculations in that the flowing bottom-hole pressure (FBHP) must be estimated instead of measured.In most situations at Kuparuk, proven hydraulic correlations allow the FBPH to be assumed within a range suitable for analysis of most pressure transient parameters, such as skin, pressure transient parameters, such as skin, permeability, and flow efficiency. permeability, and flow efficiency. In the past year, over 50 SCPBU's were completed on wells in the Kuparuk River Unit. Of these tests, over ten were measured simultaneously with downhole pressure measurement devices. These concurrent tests provide a means to evaluate the accuracy of provide a means to evaluate the accuracy of the surface calculated measurement technique through direct comparison with the current industry standard of downhole measured pressure transient testing. Results of these pressure transient testing. Results of these concurrent tests indicate close agreement after the dynamics of phase separation in the tubing have taken place. In Kuparuk wells, the first 4-8 hours of shut-in time is a period marked by the dynamic migration of period marked by the dynamic migration of natural gas from the live oil present in the wellbore and reservoir, resulting in a constantly changing fluid gradient in the wellbore. Due to the numerous complicating factors involved, a correlation to accurately model the changing gaseous-liquid gradient has not yet been developed for Kuparuk.
Consider the case of a sand stone reservoir that has been under a water or steam flooding program, that was not efficient. A lot of effort is currently being done to evaluate and recover the oil that was left in the ground. As the flood fluid has now been introduced to the Reservoir element, it becomes very difficult to find the value of the water saturation as the salinity of the flood water is different from the original formation water, and involves a lot of coring and other expensive operations to come up with the value of Sw; water saturation.
The technique suggested in this paper finds the value of the saturation using logs, both old and new, that are available for that field the old being the original resistivity logs and the new being the logs of the new well drilled and recorded after the flood. This technique agrees very well with the saturation obtained by other methods including other logs such as the EPT log, and the core analysis results, within a tolerance of + or - 7%.
In many fields that use water or steam flooding, the problem of fingering and bypassing some of the oil zones frequently happen. As a result, programs are made to recover the oil that is left behind in these secondary recovered reservoirs. The question becomes; " How much oil is left behind ? ". The problem now is that the pay zone is partly flooded, that leaves the old oil zone split by a new water zone or any other shape that might form due to the new presence of the flood water. The new water zone, however, does not have the same salinity as the flood water or the original formation water, but rather some salinity inbetween, that makes the saturation evaluation from resistivity curves a complicated problem. (Rw will vary over the zone and from one well to another for the same zone, depending on the position of the well from the flood profile )
This fact was realized by the industry and rather expensive methods are followed, such as extensive coring, Nuclear Magnetism tests, and EPT logs, etc. just to determine the oil saturation over those unswept zones.
This paper offers a solution to this problem that could save substantial expenses to answer that particular question. The results of this study particular question. The results of this study were compared to other saturation values obtained by core analysis, EPT and GST logs. The results were agreeable, and will be discussed later.
The real data tested is a case in the Wilmington field, CA. This field is a typical case of a long producer that underwent waterflooding and the producer that underwent waterflooding and the chances of bypassed oil are very much there. Fig. (1) shows what the problem would look like on a resistivity log, where a new water zone has formed within or above the oil zone. That water zone has the characteristic that it's SP curve full deflection does not reach the SSP value of the clean thick adjacent wet zone that was not mixed with the flood water. Yet, the resistivity log shows low resistance indicating water in the formation. This indicates that those two waters are different; the newer being fresher.
The solution suggested in this paper will utilize the conventional Archie's (Pickett) crossplot, with some important modifications to suit the new situation. From there we will arrive at a new defined 100% water line ( Ro-Line ) which contains the new water regardless of it's mixture, and that will be our base line for evaluating the saturations of the adjacent oil zones, ( in this case could be above or below it, as shown in the figures attached of wells #1B and 2B).
Long-term production response to matrix acidizing has been analyzed in the Stevens Sand in the North Coles Levee field in the San Joaquin Valley. Twenty-nine acid jobs on production wells, using either sequential hydrofluoric acid (SHF) or regular hydrofluoric acid (HF), have been performed over the last 15 years. SHF treatments were considerably more effective than regular HF treatments over the entire period of response to the stimulations.
The North Coles Levee field is located in the southern San Joaquin Valley, approximately 15 miles west of Bakersfield, California (Fig. 1). Production is primarily from four sandstone reservoirs in primarily from four sandstone reservoirs in the Stevens formation, a turbidite of Miocene age. Average depth is approximately 9000 ft (2740 m).
Since discovery in 1939, the field has been successively exploited through primary depletion, dry gas reinjection, gas cap blowdown, waterflooding, and CO injection. The waterflood continues to date. Cumulative production is 161 MMBO (25.6 x (10)6 m), out of 483 MMBO (76.8 x (10)6 m) originally in place. Current production is 1150 BOPD (153 m/d) from 75 producing wells.
Since 1973, 21 SHF and eight regular HF acid jobs have been performed on producers in the North Coles Levee field producers in the North Coles Levee field (Fig. 2). The acid jobs were conducted in response to (1) rapidly declining gross production rates, (2) anomalously poor well production rates, (2) anomalously poor well performance as compared to offsets, and (3) performance as compared to offsets, and (3) damaging events occurring during drilling, completion, and workovers. Over the period of incremental oil production response to acidizing (ranging from 1 to 54 months), significant differences between the effectiveness of the two acid types became apparent.
This paper describes the mineralogy of the Stevens Sand, compares the SHF and HF processes, and summarizes oil and water processes, and summarizes oil and water production responses to both acid types. production responses to both acid types. MINERALOGY OF THE STEVENS SAND
The Stevens Sand is a poorly sorted arkosic sandstone, with abundant clay matrix infilling pore spaces between the coarser grains. The Stevens was deposited as part of a deep-sea fan complex. Numerous turbidite sequences are overlain to produce a reservoir with thicknesses as great as 650 ft (195 m) (Fig. 3). Porosity is fairly constant at about 16%, but permeability varies considerably and is inversely related to the presence of the clay matrix. Liquid permeability is generally 6 md or less. permeability is generally 6 md or less. Feldspars, rather than quartz, are the dominant minerals in the Stevens Sand at North Coles Levee (Table 1). Feldspars in the Stevens Sand are the primary source for the largely authigenic clay matrix. Although x-ray diffraction indicates that clays comprise an average of 7.2% of rock weight, thin section analysis suggests that in some wells clay content may be as high as 19%. The clay fraction is composed of chlorite, mixed layer illite-smectite, illite, and kaolinite in descending order of prevalence (Table 2).
Texaco operates large steam floods in the San Joaquin Valley in which Individual wellhead mass flow rates and steam quality measurements are difficult to obtain. Uneven and unpredictable phase splitting at lateral and dead end tees is the problem. In one instance, Texaco has solved this problem by utilizing a horizontal separator to separate 10,500 BPD of 70% quality cogeneration steam.
The separator is able to deliver saturated water and dry steam. These two single phase flows can be divided into any number of flow streams and then measured using simple orifice plate, differential pressure, technology.
The steam flood distribution piping consists of the separator, two single phase trunk lines running the length of the field, and small headers located along the trunk lines. The purpose of these headers is to measure, control, and combine the water and steam for each well, using orifice meters and adjustable chokes. Because each injector is controlled separately, the Injector mass flow rates and steam qualities are independent of one another. Not only does this solve the phase splitting problem, but this flexibility phase splitting problem, but this flexibility Is helpful when some Injectors need higher or lower qualities than others. For Instance, lower qualities may be warranted for displacement patterns experiencing steam breakthrough, or for occasions where patterns requiring different qualities need to be served by the same trunk line. A 36 megawatt cogeneration facility feeds the horizontal separator which is 30 feet long, 5 feet in diameter, and 2.5 inches thick. Saturated water is taken from the bottom and dry steam is taken off the top. Both these flow streams are divided in order to serve two properties. For one property, the water and steam are measured and combined right away before feeding an existing distribution system. For the other, on which a new flood is being started, the two trunk lines run the length of the field to serve the injection headers. The hardware for each injector consists of an orifice meter and choke to control the steam, an orifice meter and choke to control the water, and a fixer to combine the two flows. All this hardware is located at the header so a choke can be set while monitoring the output from the corresponding orifice meter. A spare port on one of the headers is used, not for an injector, but to serve an existing stimulation header. In this way, cogeneration steam is used to provide all the displacement and stimulation steam requirements.
One of the problems associated with this type of operation is the chemical treatment of the dry steam line. The feedwater contains a high concentration of bicarbonate. Therefore, a neutralizing amine is added to combat the high ph caused by the formation of carbonic acid. Steam samples are collected at various points along the line and are monitored for iron concentration and ph. Also, corrosion probes and corrosion coupons are used to verify data. The goal is to hold corrosion to 0.00625 inches/year (1/8 inch over 20 years).
Decisions concerning future development options at the Kuparuk River Field are complex and interrelated. Various development strategies are being evaluated. To help address these issues, a facilities model has been added to a full field reservoir simulator. Facility limits are used with a well ranking system to shut in marginal production when equipment capacity constraints are exceeded. The model simulates field operating strategies which maximize production. Operational strategies are modelled using (1) a wellbore hydraulic routine that enables bottom hole pressures to change (reflecting the benefit of various gas lift rates), (2) a gas lift allocation correlation that was determined from field data, and (3) a gas management routine which optimizes oil production while honoring gas capacity constraints and field gas production while honoring gas capacity constraints and field gas lift needs. These gas management and hydraulic features are essential to properly evaluate future projects in a gas capacity constrained environment and can be applied to other reservoir simulation tools. An example of how the reservoir simulator is being used to address a key issue in the large scale facility expansions evaluation is included.
The Kuparuk River Reservoir contains approximately five billion barrels of original oil in place. The reservoir is located on the Alaskan North Slope, approximately forty miles west of the Prudhoe Bay Field. The field produces from two physically independent sands of the Kuparuk River Formation, a lower cretaceous, shallow marine sandstones The productive sands are Informally named the A and C Sand members. The C Sand overlies the A Sand and is highly permeable, having an average permeability thickness of 5000 md-ft (1.5 mu m2-m). The A Sand is considerably less productive than the C Sand, having an average permeability thickness of 1000 md-ft (0.3 mu m2-m). The two sands do not communicate within the reservoir; however, they are hydraulically coupled through the wellbores.
Many development issues have faced the Kuparuk River Field Unit Owners since startup in 1981. The field has experienced a variety of development processes including primary production, waterflood, a water alternating immiscible gas injection (immiscible WAG) project, and a pilot scale miscible WAG project. With these various recovery mechanisms, the field has grown in complexity. An uncertain economic climate further complicates development decisions. The Kuparuk River Field has reached a point in field development where decisions concerning future strategies are usually complex and interrelated. Various development strategies are simultaneously being investigated: infill drilling, further peripheral development, and enhanced oil recovery projects. Some of these strategies require facility additions with long equipment lead times, which necessitates early identification of field development plans and reliable rate projections. In addition, future operating strategies centering around a maturing waterflood are also uncertain. Gas lift gas requirements for wells with steadily increasing water cuts are still being investigated. Factoring these possibilities and uncertainties into the evaluation of development options at Kuparuk required enhanced simulation tools.
To address the complex nature of these decisions, a Kuparuk-specific facilities model and well management logic for a gas capacity constrained system have been added to a full field reservoir simulator. A modelling scheme specific to the Kuparuk River Field was needed because of the unique facility configuration. Equipment limits are used with a well ranking system to shut in marginal production when facility limits are exceeded. To properly simulate field operations in a compression capacity constrained environment, additional features were developed for the well management package. A wellbore hydraulics routine that enables flowing bottom hole pressures to change as a function of gas lift rates, fluid production characteristics, and reservoir pressure was implemented.
Following is a review of 51 waterflood injection well workovers designed to improve vertical sweep efficiency in the Inglewood field, California, from 1984 through 1988. A cost comparison is made for five types of workovers based on improvement in injection profile for two years after the workover. Damage mechanisms known to occur in these injection wells are: 1) bacterial slime; 2) iron sulfides; 3) calcium carbonate scale; 4) migrating clays and formation fines; 4) drilling fluid damage; and S) formation crushing during jet perforating.
An index was developed to characterize a well's injection profile with a single value, allowing objective comparison of injection profiles before and after workovers and comparing profiles between different wells. The index was developed after reviewing actual data from about 200 temperature-spinner-tracer (TST) surveys. The index is equal to the total feet of perforated sandstone taking water injection, modified to account for uniform or nonuniform vertical distribution. The index is independent of total completion interval, allowing comparison of wells with differing net pay.
The index is used to evaluate cost effectiveness of the workovers and to estimate vertical sweep efficiency of the waterflood.
Relevant data was collected from tracer-spinner-temperature (TST) surveys. An index was defined which summarizes a profile survey with a single number. Lotus and Paradox spreadsheets were created to calculate the index for each of 208 TST surveys. The index was developed out of a need to objectively evaluate injection profiles over very long completion intervals. It evolved through several discussions with other engineers and subsequent modifications.
The final index used for comparing TST profile surveys is called "Effective Feet of injecting Perforations" (EFIP). Figure 1 is a printout of the Perforations" (EFIP). Figure 1 is a printout of the database report used to calculate the EFIP for an example TST survey. Appendix 1 describes EFIP.
Similar workovers were grouped together and an average change in the index was calculated for each job type. The incremental EFIP was then multiplied by years that the perforations were open, to include the duration of profile improvement. (The resulting term of year-feet can be conceptually compared to man-years as a term in mixed units.)
The average cost of each workover type was then divided by the year-feet of added injection interval, yielding a cost per unit of improvement ($/(yr-ft)) which was used for comparing cost effectiveness of workovers.
Other sources were reviewed in the course of this study: the Petroleum Engineering literature, a recent reservoir engineering report on the Inglewood field, produced water analysis and known active damage produced water analysis and known active damage mechanisms.
INGLEWOOD FIELD BACKGROUND
The Inglewood field is located about ten miles west of downtown Los Angeles, Figure 2. It consists of two reservoirs under active waterflood and five reservoirs under primary depletion, Figure 3. The Vickers and Rindge zones are currently being waterflooded and are the focus of this report. Waterflooding began in 1954 in Inglewood and is in mature stages throughout the field. Field average watercut is 95%.