bluuebunny/crossref_metadata_2025 huggingface dataset:
Case Histories of Design and Implementation of Underbalanced Wells
Authors: Giffin David R. , Lyons William C.
Published: December 2007

As operators strive to increase production from existing reservoirs with depleted reservoir pressure, the use of underbalanced drilling and underbalanced horizontal drilling is becoming more widely used. One of the primary problems to overcome in drilling under-balanced is designing a circulating "fluid" that has an equivalent circulating density below the reservoir pressure. This paper discusses the mathematical equations used to design air drilled "under-balanced" wells. It will also show how these equations were used to design four separate wells. The presentation of actual field data will validate these equations and computer modeling used. (See Table 1) The four wells will include 1) 17,000 TVD well drilled into the Ellenberger formation with reservoir pressure at 1200 psig, 2) horizontal well drilled into the Petit formation at 5900 ft. TVD with reservoir pressure at 210 psig, 3) horizontal wells drilled into the upper Penn Formation at TVD 7800 ft. and reservoir pressure of 1000 psig., and 4) deviated wells drilled into the Ellenberger formation below 13,000 feet TVD and reservoir pressure of 600 psig.

The mathematical equations used were developed by Dr. William C. Lyons of New Mexico Institute of Mining and Technology in Socorro, NM. Computer simulations for these wells were run by David Giffin on software developed by Boyum Guo and Dr. Lyons. Each of these wells was drilled using air drilling techniques. By measuring the pressure at both surface and bottom hole conditions, the validity of the mathematical models used has been established. Air or other compressed gas can be used to reduce equivalent circulating densities to accommodate almost any reservoir pressure.
Casing Drilling Application Design Considerations
Authors: Warren Tommy M. , Angman Per , Houtchens Bruce
Published: December 2007

Casing Drilling is an emerging technology for simultaneously drilling and casing a well where the casing is used to transmit mechanical and hydraulic energy to the bit, instead of using a conventional drill-string. A drilling assembly, positioned in the lower end of the casing, replaces the tools normally located on the lower end of the conventional drill-string. This assembly is retrieved with a wireline to access bits, motors, underreamers, MWD/LWD, and other components while leaving the casing in place.

The Casing Drilling process has been used on portions of ten wells during a field trial phase. The system is still undergoing development but these wells have demonstrated the functionality of the casing drilling system.
A New Borehole Surveying Technique for Horizontal Drilling Processes Using One Fiber Optic Gyroscope and Three Accelerometers
Authors: Noureldin A. , Tabler H. , Irvine-Halliday D. , Mintchev M. P.
Published: December 2007

Current borehole surveying techniques during horizontal drilling processes utilize three-axis magnetometers and three-axis accelerometers inside the Measurement-While-Drilling (MWD) assembly. The measurements received from the three accelerometers are processed to provide the tool face angle (roll) and the deviation angle from the vertical direction (pitch). The magnetometers measure the magnetic field in three mutually orthogonal directions to provide the ongoing azimuth. Due to the massive amount of steel around the drilling rig, the magnetometers are installed inside costly non-magnetic drill collars. Moreover, the deviation of the Earth's magnetic field from ore deposits reduces the accuracy of any downhole magnetic field based measurements. The fiber optic gyroscope (FOG) currently employed in different navigation applications can be adapted for the borehole surveying. A previous feasibility study showed that the FOG has excellent immunity to the severe downhole environment. The objective of this article is to develop a new navigation algorithm utilizing the FOG mounted on the horizontal plane of the borehole assembly together with three orthogonal accelerometers. The mechanization equations necessary to process the measurements from the FOG and the three accelerometers and deliver the drill bit attitude (azimuth, pitch and roll) as well as its coordinates (latitude, longitude and depth) are provided. The accuracy of the applied algorithm was found to be about 99 %. In addition, applied optimal estimation techniques based on Kalman filter algorithms are presented to compensate for the measurement errors from the FOG and the accelerometers.
A Proven Liner Flotation Method for Extended-Reach Wells
Authors: Trahan Kevin , MacDonald Jamie , Webster Steve , Mason Colin
Published: December 2007

Based on a case history, this paper introduces a complete field-proven solution to running and cementing a liner into a world-record extended-reach well.

Flotation was used to assist in getting the liner to depth. Although floating a liner into a well is not a new concept, this case was unique, because flotation was achieved by using only standard Weatherford liner tools, with no need for special, possibly unproven, flotation devices. Weatherford also supplied unique friction-reducing devices that allowed for rotation of the liner during cementing operations.

Personnel performed extensive modeling and profile work before proceeding with operations at the well site. The preliminary modeling work revealed that, if the liner were run conventionally, the weight of the liner could create a significant friction force on the open-hole section that could prevent the liner from reaching the required setting depth. Ultimately, if corrective techniques were not applied, the liner could no longer be run into the hole, because set-down weight was limited to the block weight of the drilling rig.

In this case, the strategy was to float the entire length of the liner to minimize drag in the open-hole section, keep the drillpipe full of mud, and push the liner to the required depth.
A Stick-slip Analysis Based on Rock/Bit Interaction: Theoretical and Experimental Contribution
Authors: Challamel N. , Sellami H. , Chenevez E. , Gossuin L.
Published: December 2007

The purpose of this paper is to analysis bit stick-slip motion by using rock mechanics considerations coupled with field bottomhole data.

The data was collected using an instrumented PDC bit. This new tool enables to measure accelerations, Weight-On-Bit (WOB) and Torque-On-Bit (TOB) directly above the bit. Tests were conducted in Montrose (Scotland) at about 700 m depth in a consolidated Devonien sandstone. During several hours of testing, the sensitivity to operating and different structural parameters was evaluated. The effect of stick-slip on Rate Of Penetration (ROP) was quantified: ROP is really affected by this dynamical phenomenon which appears above a certain Weight-On-Bit threshold.

Two stages rule the drillstring behaviour. The stationary behaviour (small oscillation of the rotation bit speed around the mean value) is described by modal analysis. Experimental frequencies are in agreement with the theoretical natural ones. A perturbation of the operating parameters (generally an increasing of the WOB) makes the system bifurc towards stick-slip. The dynamical system is now governed by a non linear autonomous boundary condition, linked to the rock/bit interaction. Rock mechanics considerations justifie such a law. Numerical simulations converge on stick-slip, typical limit cycle experimentally exhibited.

The last analysis is focused on an analysis of "drill-off test". In this operating stage, the rock/bit interaction function changes. Numerical simulations, justified by clearly experimental evidence, show the benefit effect of such a test, which stabilizes the system. A discussion on the effect of the stabilizers and bit type follows as well as how to attenuate this non linear phenomenon.
Method of Rapid Stabilizing Shut-In Drillipipe Pressures for Blowout Wells
Authors: Li Xiangfang , Gang Tao , Sui Xiuxiang
Published: December 2007

A new well control method is proposed to shorten the drillpipe pressure stabilized time after shut-in. Long stabilized period is extremely harmful to well control, especially for unstable well-hore, pipe will probably be stuck due to the long shut-in time. Our new method is proved simple, practical and robust from the test results of computer simulation, physical model in full scale and application on site. It provides a new way of well control. The process of pressure buildup after shut-in is now under control. The stabilized time is shortened and the influx of invaded reservoir fluid is decreased greatly. Thus the well control becomes easy.

In our new method, using a mud or cementing pump, intermittently a certain amount of drilling mud is pumped into wellhore at a small flowing rate, resulting in the desired initial shut-in drillpipe pressure. Wild cat well, exploration well and development well are required a different initial shut-in drillpipe pressure. In terms of the pressure buildup after the first batch of drilling mud, The next pumping time and mud volume to be pumped are determined by the computer model. Our study set up the mathematical model to determine the desired initial shut-in drillpipe pressure through pumping and the computer program is coded for application on site.
Heavy-Oil Production Enhancement by Encouraging Sand Production
Authors: Dusseault Maurice B. , El-Sayed Samir
Published: December 2007

Dramatic increases in oil production rates have been achieved in many Canadian heavy oil reservoirs. These reservoirs are 30% porosity unconsolidated sandstones with oil ranging from 500 to 12,000 cP viscosity. Furthermore, many of these reservoirs have proven to be almost impossible to exploit economically with horizontal wells or with thermal processes.

After reviewing the mechanics of CHOP (Cold Heavy Oil Production), the production history of the Luseland Field in Saskatchewan is reviewed. This is almost a unique case history because conventional production, horizontal wells, and CHOP have all been attempted in a small geographic area. Encouraging sanding resulted in over a four-fold increase in oil production rate and a total extraction ratio now just in excess of 11% overall. An aggressive CHOP program implemented after many years of conventional production and after a six-well horizontal production program achieved this increase. Conventional production was marginally economic, but the horizontal wells were failures.

Several other case histories are summarized to demonstrate that CHOP wells in these reservoirs are usually just as productive as much more costly horizontal wells.

We believe that CHOP technology is a far better option than thermal stimulation or horizontal wells in many cases where the reservoir state and rock properties are suitable.
Improved Oil Recovery in Carmópolis Field: R&D and Field Implementations
Authors: Mezzomo Roberto F. , Luvizotto José M. , Palagi Cesar L.
Published: December 2007

Carmópolis Field in Sergipe/Alagoas Basin in northeastern Brazil is the country's largest onshore oil accumulation at 253 MMm3OOIP and a current total oil production of 2,880 m3/d. Discovered in 1963, it was quickly put into primary production. Waterflooding followed in 1971 at the central portion of the field. The combination of adverse fluid mobility ratio, reservoir heterogeneity and the lack of proper selective injection, led to the quick decline of production. Immediately, a major program of selective plugging, stimulation and selective injection was able to stabilize production. Waterflooding was then extended to the entire main block of the field. Well pattern was changed from five to nine-spot arrangement, with a corresponding downsizing in well spacing and injection rates. Carmópolis has also experienced several pilot projects for Enhanced Oil Recovery (EOR): polymer flooding, steamflooding and in situ combustion, respectively.

This past history of Carmópolis Field and the significance of waterflooding to oil production in Brazil with approximately 1,850 MMm3OOIP currently submitted to this method of recovery, led to the selection of Carmópolis as the target for one of the projects in the portfolio of PRAVAP - Petrobras Strategic Improved Oil Recovery (IOR) Program. The scope of this project included the review of the waterflooding operation through improved reservoir characterization and flow simulation, as well as the investigation of other IOR methods that might reverse the production declining trend. This paper summarizes the outcome of this project that went from lab research to field testing and led to the approval of operational implementations worth US$ 34 million NPV.
Improved Reservoir Management/Characterization for Independent Operators in Mature Basins, A Case Study: South Slattery Field, Powder River Basin, Wyoming
Authors: Schoeling Lanny G. , Mark Sandra
Published: December 2007

A detailed geological understanding of the reservoir along with a reservoir simulation to test the reservoir description and determine the optimum recovery method is important in successful operations of mature fields. There are thousands of oil and gas fields in mature basins that have not had the benefit of detailed study by an integrated team consisting of a geologist and an engineer. Major oil companies have long adopted this practice, assisted by the latest software tools, and now small independent operators have cost-effective means to similarly help them make reservoir management decisions. South Slattery Field case study demonstrates how a geologist using sequence stratigraphic concepts and moderately priced software can develop a reservoir model, which may be further analyzed by an engineer using a reservoir simulator affordable by independent operators.

Applying new geologic concepts in mature basins may result in a better reservoir model. A company's fields may contain old maps that relied on litho-stratigraphic correlations. For the South Slattery study, the geologic model benefited greatly from using parasequences as the framework in which to delineate the reservoir compartments. This process was facilitated by software that produced effective log displays; a color fill format used in conjunction with cut-off or cross-over allowed the geologist to detect patterns that was not obvious with a simple curve display.

A cost-benefit analysis was performed for the geologic portion of the study so that the managers of small companies can judge whether the technology is affordable. Simulation was conducted utilizing BOAST III which can be obtained from the Department of Energy at very little cost. The geological description was placed in the black-oil simulator and verified with a history match on primary production. History matching utilized both geological and engineering input with reservoir parameters varied depending on data accuracy, availability, and experience. This study demonstrated that an independent could utilize an integrated team to characterize and simulate a reservoir using affordable tools; this analysis will assist in making economic decisions on the future recovery technique and operations.

In summary this paper presents 1) the methodology of geologic characterization in the Slattery Field, 2) a description of the input data needed for simulation, 3) the history matching process, and 4) results of the simulation to determine additional optimum recovery techniques.
Use of Biocatalysts for Triggering Biopolymer Gelants
Authors: Bailey S. A. , Bryant R. S. , Duncan K. E.
Published: December 2007

Gelled polymer systems are widely used in petroleum production to modify permeability of reservoir rock. These gel systems are injectable as low-viscosity gelants and then triggered in situ to form a gel. The use of biocatalysts to trigger the delayed gelling reaction of a biopolymer gelant was evaluated in this study. The gelant was a pH-sensitive glucan biopolymer. Two bacterial strains were isolated from lake sediment and used to trigger the gelling reaction. Both strains grew anaerobically, and were mesophilic, halotolerant, and obligately alkaliphilic. Using the biocatalysts to trigger gel formation, gelation delay time was inversely proportional to initial biocatalyst concentration and gelation could be delayed up to 12 days after mixing. Each of the bacterial strains had distinct effects on the rate of the gelling reaction and permanence of the formed gel. Data indicate that these strain-specific characteristics can be exploited to design gelled polymer systems with controlled performance properties.

The new polymer system was injected into sand-packed columns, glass bead-packed columns, and Berea sandstone cores, and then triggered in situ by the biocatalyst to form gel. Analysis of core effluent indicated that the in situ gelling reaction was complete. Brine permeability of cores was decreased by two to four orders of magnitude after treatment with the new gel system. In parallel corefloods, the biocatalyzed gel blocked flow through high permeability zones and diverted flow into low permeability zones. Permeability modification with the polymer system improved sweep efficiency and increased oil recovery over waterflooding alone.
Pore-Scale Modeling of Three-Phase Flow and the Effects of Wettability
Authors: Hui Mun-Hong , Blunt Martin J.
Published: December 2007

We analyze fluid configurations in a single pore for three-phase flow in mixed-wet systems. After primary drainage solid surfaces in contact with oil may alter their wettability. We consider waterflooding followed by gas injection for any possible combination of oil/water, gas/water and gas/oil contact angles. We compute capillary pressures for the different displacement processes, find the range of capillary pressures for which the various fluid configurations are stable, and obtain expressions for the fluid saturations and conductances.

We compute three-phase relative permeabilites for a bundle of tubes of different size with constant triangular cross sections. We model gas injection starting from different initial oil saturations, Soi. We show that the oil remains connected in wetting layers down to low oil saturation with a characteristic layer drainage regime. The only exceptions are non-spreading oils in water-wet media and large gas/oil contact angles. The relative permeability of the phase of intermediate wettability depends on both its own saturation and Soi, while the other relative permeabilities are functions of their own saturation only. In water-wet media, oil is the intermediate-wet phase. In weakly oil-wet media, water is intermediate-wet. In most strongly oil-wet media, gas is intermediate-wet. This contradicts the assumptions made in many empirical models that gas is always the most non-wetting phase and that its relative permeability depends only on the gas saturation. For media that contain regions of different wettabilitites, all three relative permeabilities may depend on both their own saturation and Soi.

This work indicates appropriate functional dependencies for three-phase relative permeabilities, as well as being a necessary first step towards the development of a realistic three-dimensional, three-phase predictive pore-scale model that accounts for the effects of wettability.
Rheology of Gels Used For Conformance Control in Fractures
Authors: Liu Jin , Seright R. S.
Published: December 2007

Because extrusion experiments in fractures are expensive and time consuming, we implemented a study of gel rheology, in hopes of correlating the results to our measurements during gel extrusion through fractures. Our study focused on a one-day-old Cr(III)-acetate-HPAM gel. The elastic modulus (G') of the gel was fairly constant for strain values up to 200%. The elastic nature was evident even at strain values over 1,000%. This finding is consistent with the ease with which these gels extrude through fractures. As the polymer concentration in the gel increased from 0.3% to 1.7%, G' increased from 4 to 115 Pa. In contrast, the viscous modulus (G") remained near 1 Pa. Thus, as expected, the elastic component became increasingly dominant (over the viscous component) as the polymer concentration increased. The temperature and frequency dependencies of the elastic modulus were characteristic of those for rubber-like materials. For gels that contained 0.5% HPAM, G' exhibited a broad maximum at ~7-8 Pa for Cr(III)-acetate concentrations between 0.02% and 0.05%.

Shear stress was fairly insensitive to shear rate. When shear rate was increased by a factor of 100,000, shear stress only increased by a factor of 10. This result was consistent with our earlier observations that the pressure gradient required to extrude a gel through a fracture was fairly insensitive to injection velocity. A log-log plot of complex viscosity versus shear rate gave a slope of −0.8. This value was very similar to that for a log-log plot of resistance factor versus injection velocity that was noted earlier during gel extrusion through fractures.

Additional work is needed to establish a correlation between gel behavior in fractures versus in a viscometer.
Direct Thickeners for Carbon Dioxide
Authors: Enick Robert M. , Beckman Eric J. , Shi Chunmei , Huang Zhihua , Xu Jianhang , Kilic Sevgi
Published: December 2007

Direct thickeners for dense carbon dioxide were designed and synthesized. Each thickener contained highly CO2-soluble "CO2-philic" fluorinated groups, while "CO2-phobic" functionalities promoted viscosity-enhancing intermolecular associations. Semifluorinated trialkyltin fluorides, fluorinated telechelic ionomers, fluoroacrylate-styrene copolymers and sulfonated fluoroacrylate-styrene copolymers, were soluble to at least several weight percent in dense carbon dioxide without the use of a cosolvent. Increases in solution viscosity were measured using falling cylinder viscometry.

The most promising CO2 thickener was a styrene - heptadecafluorodecylacrylate bulk-polymerized random copolymer. The optimal composition of the copolymer was about 30 mol% styrene - 70% fluoroacrylate. For example, a 29% styrene-71%fluoroacrylate copolymer increased the viscosity of liquid CO2 by a factor of 250 at a concentration of 5 wt% and a shear rate of 20 s−1 at 297K and 34 MPa. A 0.2 wt% copolymer - 99.8 wt% CO2 solution exhibited a viscosity twice that of neat CO2 at shear rates of about 3000 s−1. Greater proportions of styrene in the thickener led to decreased CO2 solubility and solution viscosity, while lower proportions of styrene resulted in greater CO2 solubility but decreased solution viscosity. Solution viscosity increased with increasing copolymer concentration, increasing pressure and decreasing shear rate.
Immiscible CO2 Flooding for Increased Oil Recovery and Reduced Emissions
Authors: Brush Randal M. , Davitt H. James , Aimar Oscar B. , Arguello Jorge , Whiteside Jack M.
Published: December 2007

Carbon dioxide is both the most-recognized greenhouse gas as well as the second most-used injectant in oil fields, after water. This coincidence creates the possibility of injecting previously-vented CO2 to both reduce greenhouse gas emissions and increase oil recovery. Such a project has been evaluated for the Avile reservoir of the Puesto Hernandez field, located in the Neuquen Basin in west-central Argentina. This oil field produces associated gas containing approximately 60 percent CO2, which has previously been vented. The project described below assessed the feasibility of extracting and injecting the CO2 into the field to recover additional oil using an immiscible displacement process. Following an evaluation including core floods, compositional simulation, and facilities evaluation, the process was found both to have technical and economic promise in terms of improved oil recovery, and to result in reduction of both CO2 and methane emissions, the latter being an especially potent greenhouse gas. The success of this type of project would create a unique common ground for those concerned with reducing global warming and those concerned with supplying society's energy needs.
Simulation of Light-Oil Air Injection Into Viscous-Dominated and Gravity-Stable Reservoirs
Authors: Kuhlman Myron I.
Published: December 2007

Simulations of Light Oil Air Injection (LOAI) in viscous-dominated ¼ five spot models and a dipping gravity-dominated Gulf Coast salt-dome reservoir were conducted to assess performance of LOAI in Equation of State (EOS), black-oil and thermal simulators. The effect of porosity, reservoir thickness, interbedded-shale, pattern size, initial reservoir temperature, and type of gas injected were tested in the viscous-dominated model. Results indicate that lower thickness, porosity, and initial reservoir temperature reduce the predicted recovery from the thermal model. A smaller or an opposite trend was found with the other models. On the other hand, recovery from the thermal model is not affected by reduced pattern size, while it is with the black-oil and EOS models. The effect of gas expansion at high temperature is important and especially evident in the gravity-dominated salt-dome model where a circulation cell forms in the gas cap. A thermal simulator is recommended for assessing reservoir performance, unless the reservoir is especially thick, has a high temperature, and API gravity.
Gas-Steam Slug Flooding to Enhance Recovery from a Medium Heavy Oil Reservoir
Authors: Wang Deyou , Zhu Tao , Chen Demin , Bao Feng , Olsen David
Published: December 2007

China's Liaohe Oilfield is the country's largest heavy oil field and contains numerous smaller, individually named, reservoirs (oilfields) with oil viscosity ranging from 100 cp to over 50,000 cp. Because of pressure depletion, steam huff-n-puff (cyclic steam) has reached its economic limit in a number of the heavy oil reservoirs in Liaohe. Recently, a flue (exhaust) gas-steam slug process has been tested in an attempt to improve recovery of medium heavy oil, oil with a viscosity less than 1,000 cp. Pilot tests, which started in September 1998, used one injection well and 9 production wells. The pilot test conducted in the eastern part of Block Du-66 of Shuguang Oilfield showed encouraging results. Average oil production increased from 1.8 t/d before the test to 20 t/d after more than 65 days production, with a peak oil rate of 29.2 t/d. The water-cut dropped from 84% to 39%. Drop in watercut reduced operating and water disposal costs. Cost of the entire operation of the flue gas-steam is about half of the cost of steam generated by a boiler. This paper describes the design, construction and operation of gas-steam slug project. The economics of the project and success to date are encouraging. This has prompted application of the gas-steam process to recover lower viscosity heavy oil from other Chinese reservoirs.
Impact of Reservoir Mixing on Recovery in Enriched-Gas Drives Above the Minimum Miscibility Enrichment
Authors: Solano R. , Johns R. T. , Lake L. W.
Published: December 2007

Gas enrichment is an important variable to optimize oil recovery in enriched-gas drives. For slimtube experiments, oil recoveries do not increase significantly with enrichments greater than the MME. For field projects, however, the optimum enrichment may be different from the MME. The optimum enrichment is likely the result of greater mixing in reservoirs than in slimtubes. In addition, 2-D effects such as channeling, gravity tonguing, and crossflow can impact the enrichment selected.

Numerical simulation is often used to model the effect of physical mixing on oil recovery in miscible-gas floods. Unfortunately, numerical dispersion can cloud the interpretation of the results by artificially increasing the level of mixing in the reservoir.

This paper investigates the interplay between various mixing mechanisms, enrichment level, and numerical dispersion. The mixing mechanisms examined are mechanical dispersion, gravity crossflow, and viscous crossflow. UTCOMP is used to evaluate the effect of these mechanisms on recovery for different grid refinements, reservoir heterogeneities, injection boundary conditions, relative permeabilities, and numerical weighting methods including higher-order methods. For all simulations, the reservoir fluid used is a twelve-component oil displaced by gases enriched above the MME.

The results show that for 1-D enriched-gas floods, the recovery difference for enrichments above the MME increases significantly with dispersion. The trend, however, is not monotonic and shows a maximum at a dispersivity of about 3 ft. Furthermore, the trend is independent of relative permeabilities and gas trapping for dispersivities less than about 3 ft, i.e. range of possible reservoir dispersivities. For 2D enriched gas floods with slug injection, the difference in recovery generally increases as dispersion and crossflow increase. The magnitude of the recovery differences is less than for the 1-D displacements. Recovery differences for 2-D are highly dependent on relative permeabilities and gas trapping. For water alternating gas (WAG) injection, the differences in recovery increase slightly with as dispersion decreases. That is, the recovery difference is significantly greater with WAG at low levels of dispersion than with slug injection. For the cases examined, the magnitude of recovery difference varies from about 1 to 8 percent of the original oil-in-place (OOIP).
Timing of Miscible Hydrocarbon Gas Injection after Waterflooding
Authors: Jerauld Gary R.
Published: December 2007

This paper describes the strategy used in multi-contact miscible hydrocarbon gas injection into a relatively water-wet, low permeability, light-oil reservoir and how the behavior seen in fine-grid models can be scaled-up to yield approximately the same behavior in coarse-grid simulation.

Type pattern simulations are used to show that, along with WAG ratio and solvent slugsize, the timing of the start of gas injection is a key optimization variable. The results show that the most economic recovery occurs if very low WAG ratios are used and gas injection starts when the waterflood front is slightly past midway been injectors and producers. Starting significantly later or earlier can reduce incremental oil recovery over waterflooding by a factor of 2 or more.

Comparison of fine-grid and coarse-grid versions of type pattern models shows that oil recoveries are understated by 4% OOIP and floodrates are understated by 10% if rock relative permeability curves are used in the full field model. Pseudo relative permeability curves can be constructed to correct for these inaccuracies, but different sets of relative permeability curves are required for the near-injector cells and other portions of the reservoir.
Dehydration and Permeability of Gels Used in In-Situ Permeability Modification Treatments
Authors: Krishnan P. , Asghari K. , Willhite G. P. , McCool C. S. , Green D. W. , Vossoughi S.
Published: December 2007

Aqueous gels placed in oil reservoirs to reduce the permeability to water can undergo partial dehydration in which part of the water contained in the gel is expelled under an imposed pressure gradient. This paper describes a study of the dehydration behavior of a polyacrylamide-chroium acetate gel in which both oil and water were used to impose a pressure gradient on bulk gels. Bulk gels were formed in cylindrical cells. The gel was held in place by a 10-micron Teflon frit at the exit end of the cell. Brine or mineral oil at a fixed pressure was placed at the other end of the gel. Flow rates of brine exiting the frit were measured. Pressure gradients between 12 and 1130 psi/ft were imposed.

Dehydration of the gel occurred with both oil and water as the dehydrating fluids. Dehydration was characterized by the formation of a finger of the dehydrating fluid near the central axis of gel and the formation of a filter cake on the exit frit. Mass balances revealed that the amount of polymer in the filter cake was very close to the amount of polymer in the finger volume based on the initial polymer concentration in the gel. Dehydration reduced the gel volumes by 50 to 70 %. The rate and final percent of dehydration was greater when oil was used as the dehydrating fluid. Permeabilities of the filter cake and the non-dehydrated bulk gel were determined to be on the order of 1 μd for the filter cake and in the range of 0.3 to 0.8 md for the bulk gel.
Relative Permeability Modifier Preflush Fracture-Stimulation Technique Results in Successful Completion of Previously Bypassed Intervals
Authors: Brocco C. , Dalrymple E. D. , Peacock H. , Creel P. , Everett D.
Published: December 2007

A fracture-stimulation technique that includes an in-situ generated relative-permeability modifier (RPM) preflush has been used to tap previously bypassed reserves in an Argentina formation. The formation was reported to have high water-saturation levels. Fracture-stimulation treatments performed in similar intervals usually (1) intersect a stringer of water within the targeted interval, or (2) extend into the highly saturated areas above and/or below the interval. Water cuts as high as 60 to 70% have made production of such intervals uneconomical.

A major operator has used the new RPM polymer-based preflush (PBP) technique on more than 15 wells in an Argentina formation. Data gathered from the first 3 months of production economically justify the stimulation treatments. In many cases, the treatment has limited water production to less than 15%, and some applications have reduced water production to negligible levels. This paper discusses the job design, field application, and results of several RPM preflush treatments performed in this area between 1997 and 1999.
Improving Reservoir Maps by Using Petrophysical Properties of Shales, Mudstones, and Clay-Rich Silts
Authors: Allen Rob L.
Published: December 2007

Petrophysical properties of mudstones, clay-rich silts and other fine grained sediments loosely referred to as shales can provide numerous geologic characteristics to improve sand reservoir maps. Useful water salinities and rock properties caused by sedimentation may be derived from impermeable zones. Those properties often relate to and reveal depositional patterns and processes. Well log responses to shales can help to delineate reservoir components, determine depositional environments, and improve production.
Full-Scale Well Model Tests of a New Chemical Plug System for Zone Isolation in Horizontal Wells
Authors: Gomez J. A. , Mamora D. D. , Lilledal L. O.
Published: December 2007

In horizontal wells completed as open holes that are irregularly shaped or badly washed-out, or with slotted or preperforated liners, mechanical packers can not be used to isolate a water- or gas-producing zone. Consequently, a new method using chemical packers has been developed and tested. The method involves: (i) setting two chemical wellbore plugs in the horizontal section to straddle the problem zone, (ii) squeezing gel into the problem zone, and (iii) cleaning out the borehole prior to production. Using coiled tubing, the whole operation would be conducted in one roundtrip.

The new method was tested using a 60 ft. long horizontal-well apparatus consisting of an outer 12-3/4 in. PVC casing containing two concentric metal screens (ID's 9 in. and 6 in.). Space between the screens was packed with sand, forming a 6-inch wellbore with a 1-1/2 inch thick formation, into which a 4-1/2 inch pre-perforated liner was placed. A gel-placement tool was placed inside the liner. The tool consisted of a 1-1/2 inch tubing to spot/squeeze the formation gel, an internal % inch tubing to spot the wellbore plug, and outer rubber elements for focussed gel placement. Model temperature was set at 110°F by circulating hot water through the apparatus.

Two runs were made, each consisting of spotting a 40 ft. long K-MAX wellbore plug, followed by spotting and squeezing PERMSEAL across 20 ft. of the borehole. (From symmetry, the placements represent a dual wellbore plug each 40 ft. long straddling a 40 ft. problem zone). After the formation gel had set, the apparatus was disassembled, showing the chemical plug had completely filled the borehole, strongly adhering to the borehole surface with no slumping. The formation gel penetrated and consolidated the formation. The tests confirmed the viability of the new zone isolation method that is planned for field-testing.
Verification of a 3D Hydraulic Fracturing Model Against a Field Case
Authors: Yamamoto K. , Gutierrez M. , Shimamoto T. , Maezumi S.
Published: December 2007

A three-dimensional simulator for the IOR hydraulic fracturing technique has been developed by the authors based on the theoretical coupling of fluid flow and fracture mechanics models. Heterogeneous formations of hydraulically-induced fractures such as non-planar curvilinear shaped fractures in a complex stress field and unsymmetrical fractures generated from deviated or horizontal boreholes are modelled using fully coupled modelling of fracture opening and injected fluid flow in the simulator. The hydraulic fracturing processes including the post-shut-in process are calculated so as to satisfy the equilibrium of injected fluid volume, fracture volume and leak-off volume. The models of physical phenomena, the fundamental algorithms and numerical techniques are introduced, and their applicability to the conditions of real field problems as well as the theoretical and numerical correctness and choice of the models are verified. The pressure history data during the injection and post shut-in periods obtained from fracturing in a North Sea field are used for the evaluation, with the formation model determined by wireline logging and empirical knowledge. The simulation results suggested the adopted fracture propagation criteria need to be reviewed. Nevertheless, history matching of the results of the bottom hole pressure between the numerical and real data confirms that the models developed by the authors can be used to estimate the geometry and extension during hydraulic fracturing.
Estimation of Reservoir Properties by Monte Carlo Simulation
Authors: Nakayama Kazuo
Published: December 2007

The shallow gas zone in the Pantai Pakam Timur (PPT) field, located in Northern Sumatra, Indonesia, has recently become an important target for development. However, only two wells were drilled in peripheral part of the field. In this situation the method of Geostatistics is hardly applied because of less control points, but there is a new suitable method to estimate reservoir properties under the condition of such few control points (GDI: Geology Driven Integration Tool). To compensate few controls, GDI creates pseudo-wells by Monte Carlo Simulation method with regional geological constraints in its regulation, and generates theoretical seismic traces from them. Then the suitable seismic attributes are selected after checking the proportionality with the given reservoir property. Finally the artificial neural network (ANN) is applied to detect the weighting factors, which relate the selected seismic attributes to the given physical reservoir properties. We apply this method to the 2-D seismic records in the PPT field to extract successfully the distribution of porosity and thickness of the gas sandstone reservoir. The most prospected area is figured out in the southern part of the field, where the net thickness of gas zone is estimated to increase 27 meters with fairly higher porosity of 28%, which can be fairly confirmed by the well proposed and drilled by this study. Once getting the distribution, it is easier to calculate the total rock volume of the target reservoir under non-homogenized situation, and hence to progress on estimating more precise volume of reserves in place. Thus this method has an advantage in estimating reservoir characters from a few well data in the early development stage, or even in the late exploration stage. It is certainly important for asset managing that new idea should save the cost even in the stage of exploration.
Accuracy and Efficiency Evaluation of EOS Computation Methods for Compositional Simulation
Authors: Honami Y. , Arihara N. , Yazawa N.
Published: December 2007

A field study by compositional simulation results in expensive computation by a huge number of phase equilibrium calculations. The common method of reducing the computation time is to describe the fluid by lumping its components into several pseudo-components. The main drawback of pseudoization is the loss of detailed compositional information on reservoir fluids.

This paper reports results of evaluation studies on accuracy and efficiency of different computing methods of equation-of-state incorporated in a compositional simulation model. The compositional model was formulated by the IMPES approach. The computation methods used for iterative EOS flash calculations are the successive substitution iteration (SSI) method, Newton method, their combination, and a generalized Michelsen method to reduce the number of independent variables.

Performances of the flash computation methods were evaluated by simulating behavior of a single well in gas condensate and volatile oil reservoirs, where the reservoir fluids were grouped into 5, 10, and 16 pseudo-components for each reservoir. Simulation demonstrated high effectiveness of the parameter reduction method showing significant decreases in flash computation time compared to the conventional methods, particularly when the number of pseudo-components was increased.
Non-Uniqueness of History Matching
Authors: Yamada Tomomi
Published: December 2007

A history-matched reservoir model cannot be unique, because the same production history could be fit by different reservoir scenario. This paper presents a field story where the risk arising from such non-uniqueness is highlighted.

The first history matching on the field was performed to understand its drainage mechanism. Interaction of gravity and viscous forces on vertically heterogeneous system clearly explained the production performance. Based on that finding, an infill program was proposed and was executed. The first well hit the remaining gas, but its productivity was less than expected. Spatial distribution of sand grain size was reviewed and it was presumed that the formation productivity at that location was originally good, but had been impaired over the production period. As the reservoir pressure had declined significantly, excessive permeability reduction due to rock compaction was suspected as the reason, for which no core data was available. The second simulation study was conducted to access that effect. The history was matched with different scenario than the first study and the location for the second infill was proposed, where an existing well happened to be producing from other horizons. Although its core obtained on the target zone suggested very high permeability even after compaction, the second infill turned out to be dry. The productivity impairment proved to be true, but permeability compaction was not enough reasoning for the dry hole. Underestimation of trapped gas saturation under overburden conditions was suggested by its well log, which was consistent with other evidence. The third history match was made and finally concluded that significant amount of gas was left, but as a non-continuous phase and therefore, was practically unrecoverable.

One must be extremely careful in the choice of reservoir parameters to be evaluated in history matching. Preparing more than one reservoir scenario will be preferred.
Interpretation of the Fluid Distribution and GOR Behavior in the Yufutsu Fractured Gas-Condensate Field
Authors: Ghorayeb K. , Anraku T. , Firoozabadi A.
Published: December 2007

The Yufutsu field is a new naturally-fractured reservoir in Japan with negligible matrix porosity and permeability. This large reservoir contains near-critical gas condensate fluids with unusual fluid distribution and production. The GOR shows a decreasing trend. This is perhaps the first report of such an observation in the literature. Another interesting and perhaps related observation is that measured data in some wells show the gas richness decrease with depth; methane increases while heptane-plus decreases with depth. Steady-state data from 5-km long wells at shut-in conditions show liquid in the middle, and gas in the top and bottom.

We used the expression of total diffusion flux (molecular, pressure, and thermal diffusion) to analyze and interpret the data in the Yufutsu field. One-dimensional and two-dimensional computations were performed using the Newton method and a new robust algorithm. Predictions were made in the entire reservoir using one single PVT sample in good agreement with data. Based on this work, it is concluded that thermal diffusion significantly affects the fluid distribution in the reservoir with consequence of decreasing the GOR produced.
The Japan National Data Repository: A Multi-User Database Challenge
Authors: Dent Logan , Kenji Akiyoshi
Published: December 2007

The Japan National Oil Corporation has constructed a National Data Repository to address the data management needs of both JNOC and the Japanese oil industry at large. Before this project, JNOC had difficulty managing the vast amount of data that it acquired each year. The costs associated with data management were large as well. Since the creation of the Repository, JNOC has been able to meet several goals. First, the secure and entitled storage of well and seismic data is ensured. Second, those data are more readily accessible by all potential users. Third, it has begun to unify the data management practices at JNOC, making them easier to maintain and define. It is also allowing users to go to a single place for all their data needs. Fourth, the project has reduced data management costs at JNOC and will do so for the Japanese oil companies as well. As part of its service to the local industry, JNOC is providing the NDR facility and expertise to all oil companies in Japan. This will allow them to reduce their data management costs, for both JNOC-sponsored projects and any others they choose to house at the NDR. The facility makes this possible by providing a fully entitled data store.
Evaluation of Cyclic Steam Injectors in China
Authors: Mao M. L.
Published: December 2007

For more than a decade, several fields in China have produced heavy oil from cyclic steam thermal operations. High temperature (650F) steam has been injected into the reservoirs. One field operates cyclic steam wells completed at 1600 meters in depth. This paper describes an innovative system to measure continuously, from surface to downhole, the pressure, temperature, and spinner responses in these steam injectors. Compelling data is presented to evaluate wellbore heat loss, steam injection profiles, and reservoir properties. A unique wellbore heat-loss model applies the measured temperature data to quantify downhole steam quality. Steam injection profiles have been obtained by analyzing spinner data against perforation intervals. During the steam soaking period, downhole pressure and temperature fall-off behaviors have been observed. The analysis of pressure fall-off curves yields wellbore skin and reservoir permeability. A new model to analyze temperature fall-off curves, by applying the Marx-Langenheim theory and a new set of type curves, yields heat transfer coefficients and steam swept zone size in the reservoir.