Oil recovery by the use of steam injection techniques involves the evaluation of steam properties at varying temperature, pressure properties at varying temperature, pressure and volume. This evaluation is necessary in order to determine heat losses and the varying nature of steam quality at the surface lines, wellbore and within the reservoir during the steam Injection process. process. Several authors have developed correlations for pressures below 500 psi and yet others in most recent publication have developed in some instances, several sets of correlations for the steam properties as a function of pressures between 500 psi to 2500 psi. pressures between 500 psi to 2500 psi. This work presents an innovative mathematical model that predicts the properties of the steam as a function of pressure from as low as 1 psi to as high as 3200 psi as obtainable in revised steam tables (laboratory data).
The computer model presented here is about 99.98% accurate and was developed based on numerical analysis techniques, in combination with the use of an advanced statistical package available at USL Computer System. package available at USL Computer System. The powers to which the pressure was raised was obtained and suitable designed for this task. The model uses an equation developed especially for this computer program written in Fortran 77.
It Is now possible to determine the value of steam properties as a function of pressure for any practical range of pressures. The values obtained from the correlation closely match the experimental values given in professional steam tables. professional steam tables. In general the results generated by this new correlation are far better than any other correlations that have been published at present. present. P. 602
This paper presents the screening tests conducted to determine the feasibility of caustic steamflood at Schewing formation in Bayou Bleu Field Louisiana. The evaluation process and methods include a broad range of laboratory tests which can be applicable for screening any field trial of chemical steamflood or ordinary steamflood. The minerology, and rock properties such as porosity and permeability were properties such as porosity and permeability were determined by core analysis. The mineralogy test consists of petrographic study of thin sections, scanning electron microspy, EDAX and x-ray diffraction of formation rock samples before and after treatmentwith varying concentrations of caustic solutions. The reservoir fluid analysis involved the determination of oil: gravity, density and viscosity at varying temperatures and caustic concentrations. Also the PVT parameters and the acid number of the oil were determined.
The criteria used for screening various concentrations of caustic solution for high temperature application include: the effect of temperature on caustic-oil and caustic-rock interaction, the reaction kinetics of caustic-oil and caustic-rock, caustic-oil relative permeabilities, caustic-oil interfacial tension and oil recovery performance. The most favorable designed caustic performance. The most favorable designed caustic steamflood recovered 15% more of initial oil-in-place than the conventional steamflood.
Estimates of field performance ranged from 10% to 25 of more additional oil recovery by caustic steamflood than by conventional steamflood. Based on these screening test a field trial of cyclic caustic steam injection was carried out as a prelude to a proposed 5-spot caustic steamflood pilot project.
The Schewing formation Bayou Bleu Field Iberville Parish, Louisiana was under economic primary Parish, Louisiana was under economic primary production aided by weak bottom water drive for many production aided by weak bottom water drive for many years. However, a considerable amount of oil is left behind even in water-out zones because of the low oil gravity (18 degrees API) Laboratory tests indicated that oil displacement efficiency can be substantially improved by steamflooding. These tests also showed that between 10 to 15% of more additional oil can be recovered, by adding a suitable concentration of sodium hydroxide to the flood steam, than by conventional steamflood. The incremental oil recovery of caustic steamflood over conventional steamflood seems to stem primarily from improvement in sweep efficiency. Steam drive tends to override the lower portion of the formation which is swept by warm condensate. During caustic steam drive the lower part of the formation is swept by warm condensate containing surfactants generated in-situ by the reaction of caustic with organic acids in the oil. The effects of these surfactants on multiphase flow mechanisms are well documented by other studies.
The purpose of this paper is to present the work done to screen the feasibility of caustic steamflood at Schewing formation of Bayou Bleu Field. The laboratory study consists of: (1) mineralogy, analysis, (2) acid number determination, (3) the analysis of oil and formation water physical properties, (4) determination of oil-water properties, (4) determination of oil-water interfacial tensions at different temperatures and caustic concentrations, and (5) displacement tests resulting in evaluation of relative permeabilities and capillary numbers at varying temperatures and caustic concentrations.
When evaluating the technical success of thermal operations, one of the most important factors to be determined is how efficiently the heat is distributed within the reservoir. Temperature logging is the standard diagnostic technique for monitoring the vertical heat distribution in the near wellbore region of a well subjected to thermal operations. This paper deals specifically with the use of the log-inject-log temperature ionizing procedure in a cyclic steam application. In particular, the limitations of the procedure and the value of the information obtained is established using field examples from an experimental cyclic steam pilot project in the Cold Lake region-of Alberta, Canada.
Presently, there are conflicting opinions regarding the Presently, there are conflicting opinions regarding the suitability of various operating procedures for thermal logging and the analysis of the data. This uncertainty was addressed by mathematically modelling certain aspects of the log-inject-log temperature logging procedure. Numerous factors were found to influence the measured wellbore temperature: the treatment of the wellbore prior to logging, the accuracy of the logging tool, influx of reservoir fluids into the wellbore and the bottomhole pressure. The effect of each of these factors on the temperature logs taken was investigated which contributed to the development of a recommended temperature logging procedure.
There are three basic methods used to determine the heat distribution in a reservoir subjected to thermal recovery processes:
1) Temperature observation wells. 2) Injection/production well temperature logging. 3) Post-steam (or post-combustion) coring.
The significant cost of observation wells and post-thermal coring has often precluded their use in thermal projects even though they provide the most reliable information regarding the areal and vertical heat distribution in the reservoir. As a result, temperature logging in injection and/or production wells has become the tool engineers rely upon most to understand the heat flow within the near-wellbore region of a steamed well.
Temperature logging has been used for many years in the petroleum industry, however, most of the applications described in the literature are centered around conventional oil recovery. As well, it has been used to identify injectivity profiles in water injection wells as well as a remedial tool to identify operating problems. Much emphasis has been placed on the extraction of quantitative information from temperature profiles as well as identifying the factors which could influence them.
There is limited information available in the literature on the application of temperature logging in steam-based thermal operations, in particular that related to log-inject-log temperature logging in cyclic steam applications. Most of the available literature deals with the interpretation of temperature logs obtained from observation wells. Some authors have utilized temperature logging to identify operational concerns related to steam injection. Leshchyshyn and Seyer were able to overcome inconsistencies they observed while running temperature logs in a steamed oil sand reservoir by designing a modified logging tool. A comprehensive review of thermal monitoring techniques in wells subjected to steam injection was presented in a paper by Dugdale et al. The paper also included a mathematical model for interpreting data obtained using the log-inject-log temperature logging technique.
The objective of this paper will be to expand upon the current understanding that exists in the literature when evaluating the heat distribution around a steamed well using log-inject-log temperature logging. It is important to note that a temperature log only provides a vertical temperature profile of the fluid residing in the wellbore at the time of logging.
Four wells have been completed on platform Irene at inclinations as high as 87 degrees. The most recent well, #A-16, was drilled to a total measured depth of 14387', with a horizontal departure of 12740' at a tree vertical depth of 4420'. Over 73% of the well path was at an inclination at which incremental drag forces exceeded the incremental inclined buoyed weight.
Major accomplishments for this will include:
- A 9-5/8" casing string was easily run to 8678'MD utilizing buoyancy assistance to minimize drag forces. Drag data proved that without buoyancy assistance the casing would not have made it past 7500'MD.
- Special drill string design minimized trip time while drilling by maximizing the depth at which pipe could be run without rotation. This same design technique enabled pushing open hole logs for over 5300' to 14040'MD, while conventional drill pipe conveyed logging would barely have made it out of the 9-5/8" casing shoe.
- Almost 6000' of 7" liner was rotated down the hole utilizing an innovative hydraulic releasing tool.
In addition to the above, this paper addresses well path and mud program design considerations, as well as problems encountered while drilling and completing the well.
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.
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.
Because of its many advantages, including safety, accuracy, and instantaneity, closed-chamber drill stem testing continues to gain popularity as a well testing technique. popularity as a well testing technique. Although commonly performed, closed-chamber tests typically require manual reading of pressure gauges and manual recording of pressure gauges and manual recording of data.
This paper will describe a computerized system for automatic collection and analysis of closed-chamber test data. Using an IBM-compatible micro-computer and newly developed correlations, the system calculates maximum surface pressures vs. time for pure gas, gas-saturated water and gas-free water influx and displays the curves on the computer's screen. During the test, it reads from any of up to three pressure transducers, records the surface pressures and instantaneously displays them on the pretest planning graph. Following the test, it calculates flow rates for assumed pure gas and pure water flow and, as requested, plots pressure or either of the two rates versus time.
In addition to the computerized system for acquiring the data, the paper will describe and diagram the manifolding system for measuring the surface pressures. The manifolding system was designed to (1) enable pressures to be read from any of a set of pressures to be read from any of a set of three transducers, (2) keep the transducers in a relatively safe area away from the rig floor, (3) tap the chamber's surface pressure at the control head instead of at the floor choke manifold, thereby eliminating chicksan hoses and swings and the accompanying potential for pressure leakage, and (4) allow potential for pressure leakage, and (4) allow components to be removed relatively easily for servicing.
In summary, the paper will describe (1) the computerized system for acquiring closed-chamber DST data, (2) the enhanced and newly developed correlations and (3) the transducer manifolding designed for these tests. Diagrams of the manifolding and examples of tests will illustrate the paper.
Geothermal gradients and thermal conductivities were measured in three oil-saturated formations having different lithologies at one location in the southern San Joaquin Valley, California. The three lithologies in order of increasing depth were a sandy conglomerate, diatomite, and porcelanite, respectively. porcelanite, respectively. The geothermal gradients were measured with arrays of thermocouples in dry observation wells prior to steam injection in the area. The measured gradients for the three lithologies were 1.8, 5.8, and 2.3 degrees F/100 ft (33, 106, and 42 mK/m), respectively. The geothermal gradient through the sandy conglomerate and the porcelanite are consistent with published valued for this area (Sass, J.H., Galanis, S.P., Jr., and Munroe, R.J. : Measurement of Heat Flow by a Downhole Probe Technique in the San Joaquin Valley, California (1982) USGS Open-File Report 82-819), but the gradient through the diatomite is significantly higher.
Thermal conductivities of these formations were measured on core taken from nearby wells. Because thermal conductivity varies with porosity and oil saturation, core samples were selected for each lithology that had values equal to the average of their respective formations. The thermal conductivities were measured using the steady-state, divided-bar method at 150 and 300 degrees F (66 and 149 degrees C). The measured values for the sandy conglomerate at the low and high temperatures values were 0.71 and 0.77 btu/( hr-ft2- degrees F/ft) (1.22 and 1.33 W/m-K), respectively. The values for the diatomite were 0.35 and 0.51 Btu/(hr-ft2-0F/ft) (0.61 and 0.88 W/m-K), respectively, while the values for the porcelanite were 0.63 and 0.67 Btu/(hr-ft2-0F/ft) (1.09 and 1.16 W/n-K), respectively. The thermal conductivity of the diatomite was considerably lower and its temperature dependence was greater than that of the other formations. These data are consistent with published values for other sedimentary rocks (Anand, J., Somerton, W.H., and Gomaa, E. : Predicting Thermal Conductivities of Formation from Other Known Properties, Soc. Pet. Engr. J. (1973) Vol. Properties, Soc. Pet. Engr. J. (1973) Vol. 13, No. 5, pp. 267-273).
The geothermal gradients and thermal conductivities were multiplied to yield the local geothermal heat flow. The formation thermal conductivities were determined by linearly extrapolating the measured conductivities to the temperatures at the midpoint of each formation. For the sandy conglomerate, diatomite, and porcelanite, these temperatures were 90, 100, and 115 degrees F (33, 38, and 46 degrees C), respectively. The resulting heat flows were 0.012, 0.016, and 0.015 Btu/(hr-ft2)(38, 50 and 47 mW/m), respectively. The difference between these numbers are from the uncertainties in the measured gradients and conductivities. These heat flows are consistent with published values for the area (Gosnold, W.D. and Fischer, D.W. : "Heat Flow Studies in Sedimentary Basins," Thermal Modeling In Sedimentary Basins. Burrus, J. (ed.), 1st IFP Exploration Research Conference, Carcans, France, (1985).
This study has demonstrated that thermal properties of oil saturated rocks can vary properties of oil saturated rocks can vary significantly with lithology, particularly where diatomite is present. Such variations, if not properly accounted for, can lead to errors in the estimated formation temperatures, fluid properties, and heat flows.
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.
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.