bluuebunny/crossref_metadata_2025 huggingface dataset:
New Polymer Fluid for Hydraulic Fracturing in Russia
Authors: Fu D-K.. , Fedorov A.. , Prudnikov A.. , Mauth K.. , Lungwitz Bernhard
Published: July 2010

Borate-based fluids have been widely used as fracturing fluids for hydraulic fracturing treatments for several decades. Although the fluid system had been studied extensively and the importance of shear recovery was fairlywell understood, the rate of shear recovery for different pumping conditions was still an issue in question. It was commonly believed that fluids crosslinked with borate had reversible shear recovery after exposure to pumping through tubing and perforations. As a consequence, fluids with inadequate shear recovery have been used, resulting in premature screenouts and unnecessary high polymer loadings. We will show that the shear recovery rate is influenced by several physical and chemical factors, such as temperature and pH. Based on the understanding, we have developed a novel fracturing fluid with much-improved shear recovery and simplified operational requirements.

We present the laboratory development of the novel fracturing fluid based on guar and a novel borate crosslinker. The crosslinker is a solid borate material, which allows controllable crosslinking through slow dissolution and instant shear recovery. We used a simple experimental method to study shear recovery behavior in the laboratory and field environment. The new fluid shows excellent compatibility with water sources used for fracturing treatments in western Siberia. The use of dry crosslinker also results in the reduction of polymer loading from 4.2 kg/m3 to 3.0 kg/m3leading to higher proppant pack conductivity. We also describe the field cases of the new fracturing fluid.

The new fluid has significant advantages over the existing technology because of better shear recovery, lower polymer loading, and operational simplicity. It is well suited for operational, logistical, and reservoir conditions in Russia.
A Study of Diversion Using Polymer-Based In-Situ Gelled Acids Systems
Authors: Gomaa A. M. , Mahmoud M. A. , Nasr-El-Din H. A.
Published: July 2010

In-situ gelled acids that are based on polymers have been used in the field for several years, and were the subject of many lab studies. These acids used in stages to block the treated zone and forcing the next regular acid stages to the untreated zones. An extensive literature survey reveals that there are conflicting opinions about using these acids. On one hand, these acids were used in the field, with mixed results. On the other hand, recent lab work indicated that these acids can cause damage under certain conditions.

The ability of polymer-based in-situ gelled acids to divert regular acids was studied using parallel core flood setup. The sequence of the injection involved In-situ gelled acid at 5 wt% HCl stage followed by regular acid at 15 wt% HCl until acid breakthrough. Experimental results show that even for nearly the same permeability formation (1:1.1), regular acid preferred to flow only through the high permeability zones. Therefore, diversion was needed for all acid treatments. At an injection rate of 1 cm3/min, in-situ gelled acid plugged the two cores. For low permeability contrast (1:2), polymer was able to divert the acid with permeability enhancement in both cores.

For high permeability contrast (1: 20 up to 25), in-situ gelled acid was able to divert the acid only at injection rate less than 10 cm3/min. However, at higher injection rates, in-situ gelled acid was not able to build enough pressure that could force the regular acid into the low permeability core. Increasing the injection rate reduced the viscosity of the in-situ gelled acid. Therefore, acid injection rate should be determined based on the expected fluid viscosity in the formation. The results obtained can be used to better design acid treatments in carbonate reservoirs.
An Experimental Study of Alkaline Surfactant Flooding in Ultra Shallow Heavy Oil Reservoirs
Authors: Hunky Rabia Mohamed , Wu Yongfu , Bai Baojun , Dunn-Norman Shari
Published: July 2010

Economic recovery of heavy oil from ultra shallow oil reservoirs (<500 ft) is of interest as many such reservoirs exist throughout Utah, Missouri, and California. EOR methods, such as thermal flooding, can be limited in these ultra shallow situations, and other methods of heavy oil recovery are of interest. A study of alkaline-surfactant flooding for the Pennsylvanian Warner sand in Western Missouri has been conducted. This work has included testing more than 30 commercial surfactants and using sands saturated with heavy oil (API 17). It has been found that a few of surfactants can create a stable emulsion with the Warner heavy oil and the formation brine. In all cases examined, highest recovery is from water wet sands. Chemical flooding tests have found that using these surfactants is better than using other conventional ones. This study benefits the industry by demonstrating the applicability of alkaline surfactant flooding to the Warner sands of Western Missour. This paper presents the detail experimental methods necessary to extrapolate this work to other ultra shallow heavy oil reservoirs. In our experienments, viscosity of Missouri heavy oil can be reduced from 18518 cp to 2.5 cp at 25 °C through emulsion of certain surfactants. Emulsion of the heavy oil and formation brine is stable for several weeks at 25 °C. But heavy oil in the emulsion can be easily separated without addition of deemulsion agent. Alkaline-surfactant (AS) system can change wettability of oily sand from strongly oil-wet to water-wet. Heavy oil recovery by AS flooding test at 25 °C has been improved significantly. Considering the total volume of heavy oil in the United States is 100~180 billion barrels and a significant amount of these reserves are in ultra shallow reservoirs (<500ft). Results of our work demonstrate that alkaline surfactant flooding can be effective on enhancing oil recovery in the ultra shallow heavy oil reservoirs.
Gel Damage Remediation by Evaporative Mechanisms: A Laboratory Investigation
Authors: Le Duc , Mahadevan Jagannathan , McQueen Ken
Published: July 2010

Polymeric gels are widely used in hydraulic fracturing operations to produce natural gas from tight sands. The recovery of injected gel is often poor and large quantities are left behind, which can cause a loss in gas productivity due to a reduction in the fracture conductivity. In this paper, we present a novel study of remediation of gel damage from proppant packs by dry gas injection. We experimentally investigated removal of polymeric fracturing fluid gels from proppant packs and recovery of gas flowrate at constant pressure drawdown conditions.

The gel removal process takes place in two steps, the first being a viscous displacement process which is followed by an evaporation process. Due to the high viscosity, gel removal by simple displacement is ineffective and only 20-30% of the gel is removed at high drawdown pressures and only 3-5 % of the undamaged flowrate is recovered. However, when dry gas is injected, the entire water content in the gel is removed due to evaporation. Results from experiments conducted with sandpacks and fracture-packs show that about 40% of the undamaged flowrate is recovered by dry gas injection. Additional treatment of the trapped gels with alcohol solvent shows that gas flowrate recovery is greater and achieved faster if the dry gas treatment is preceded by a single alcohol soak treatment. The alcohol treatment improves recovery of gas rate due to greater volatility which enhances the evaporation rates.

Dry gas injection is effective in removing water content of the gel from sandpack and fracture-pack. Hence the residual gel saturation is lowered, leading to greater gas relative permeability and gas flowrate. A mathematical model based on drying front propagation is developed to predict the rate of water removal and the recovery of gas rate in damaged laboratory scale fracture and sandpacks. The model prediction agrees well with experimentally observed gas flowrate recovery in gel damaged cores.
Effect of Gravity, Flow Rate, and Small Scale Heterogeneity on Multiphase Flow of CO2 and Brine
Authors: Kuo Chia-Wei , Perrin Jean-Christophe , Benson Sally M.
Published: July 2010

A series of steady state multiphase flow experiments at a range of fractional flows and flow rates have been conducted using Berea Sandstone. Using the multiphase flow simulator TOUGH2 MP with ECO2N module, carbon dioxide saturation distributions, average saturations, and pressure gradients across the core were calculated to determine the influences of sub-core scale heterogeneity, gravity and flow rate on brine displacement efficiency. It is found that measured CO2 saturation patterns can be replicated using simulation models that include spatially varying porosity, permeability and capillary pressure curves.

The interplay of viscous, capillary and gravity forces in core flood experiments is also investigated at different Gravity and Capillary numbers representative of those expected for a typical sequestration project (Gravity numbers: 0~1000 while Capillary numbers: 10-6~10-10). These dimensionless numbers span the range of conditions expected in the near-well region to leading of the plume which may be up to 5 km or more from the injection well. Simulations show that the efficiency of brine displacement and saturation distributions during vertical displacement fall into three separate regimes. (1) At high flow rates representative of the near-well region, the brine displacement efficiency is nearly independent of flowrate. (2) When the Capillary number drops below 10-7 and the gravity number is 2, both the heterogeneous and homogenous cores display flow rate dependent saturation distributions, with brine displacement efficiency dropping by about 80%. Most of this effect is caused by the influence of gravity, as the decrease in brine displacement efficiency is only slightly smaller for heterogeneous cores. (3) At very low capillary numbers, the brine displacement efficiency appears to asymptotically approach a constant value which is independent of flowrate. In this regime, heterogeneity leads to a large reduction in brine displacement efficiency, which is independent of gravity.
Reservoir Simulation of Cyclic Steam Injection Including the Effects of Temperature Induced Wettability Alteration
Authors: Hascakir B. , Kovscek A. R.
Published: July 2010

Cyclic steam injection into representative, low-permeability, hydraulically fractured, diatomaceous, heavy-oil formations is investigated using reservoir simulation. Previous laboratory research has shown that diatomite reservoir rocks exhibit temperature-dependent wettability. Water-oil and liquid-gas relative permeability are varied here and a reservoir simulator used to evaluate the effects on oil recovery. Sensitivity studies are carried out for relative permeability curves compiled from literature for diatomaceous reservoirs. The various parameters included in the analysis are relative permeability end points and viscosity variations with increasing temperature, rock and fluid properties (such as thermal conductivity and heat capacity), injected steam temperature, pressure, and quality, bottomhole pressure for injectors and producers. The results indicate that the liquid-gas relative permeability affects process performance most sensitively because gas displacement determines the shape of the heated zone during cyclic steam injection. For the recovery of heavy oil from diatomaceous formations, realistic evolution of the liquid-gas relative permeability at steam temperatures increases the oil recovery in the range of 15 to 60% of the OOIP in comparison to cases with no evolution of wettability with temperature. Very short two week cycles (inject-soak-produce) make more oil and show greater sensitivity to the evolution of wettability with temperature.
Evaluation of CO2 Injectivity from Waterflood Values
Authors: Nagineni Venu , Hughes Richard G. , D'Souza David , Deets Kenneth M.
Published: July 2010

Carbon dioxide flooding is a common IOR method employed in fields which have relatively easy access to CO2. In some cases, estimating the CO2 injection rate is the most important design parameter which decides the planning, field implementation and eventual success of a flood. This paper presents a method for evaluating this important parameter from data that should be readily available for a field.

Water injectivity index values from fields which have undergone waterflood operations are compared to injectivity index values for the same field while undergoing CO2 flood operations. Different methods for evaluating the indices are presented as is a process for estimating the CO2 injectivity value from data from secondary operations.

The correlation developed has been verified on injectors which were converted in the same field. Initial injection rates calculated from this correlation were in closer agreement to actual injection rates than those predicted by other theoretical formulas.
Intelligent Time Successive Production Modeling
Authors: Khazaeni Y. , Mohaghegh S. D.
Published: July 2010

Production data analysis has extensively been applied to predicting the future production performance and field recovery. These applications are mostly on a single well basis. This paper presents a new approach to production data analysis using Artificial Intelligence (AI) techniques where production history is used to build a field-wide performance prediction models. In this work AI techniques and data driven modeling are utilized to predict future production of both synthetic (for validation purposes) and real field cases.

In the approach presented in this article production history is paired with geological information from the field to build datasets containing the spatio-temporal dependencies amongst different wells. These dependencies are addressed by compiling information from Closest Offset Wells (COWs) that includes their geological and reservoir characteristics (spatial data) as well as their production history (temporal data).

Once the dataset is assembled, a series of neural networks are trained using backpropagation algorithm. These networks are then fused together to form the "Intelligent Time-Successive Production Modeling"(ITSPM) system. This technique only uses the widely available measured data such as well logs and production history of existing wells to predict a) future performance of the existing wells, b) production performance of the new (infill) wells and c) the initial hydrocarbon in place using a "volumetric-geostatistical" method.

To demonstrate the applicability of this method, a synthetic oil reservoir is modeled using a commercial simulator. Production and well-log data are extracted into an all-inclusive dataset. Several neural networks are trained and validated to predict different stages of the production. ITSPM method is utilized to estimate the production profile for nine new wells in the reservoir. Furthermore, ITSPM is also applied to a giant oil field in the Middle East with more than 200 wells and forty years of production history. ITSPM’s production predictions of the four newest wells in this reservoir are compared their actual production.
Experimental and Theoretical Studies of Flocculated Asphaltene Deposition From Oil in Porous Media
Authors: Rezaian A. , Kordestany A. , Jamialahmadi M. , Moghadasi J. , Khoshdaregi M. Yousefi , Alipanah M. , Sefat M. Haghighat
Published: July 2010

Formation damage due to asphaltene deposition in oil reservoir is an issue for many countries that can have strong effect on oil production during heavy oil recovery, miscible flooding, and even primary recovery. Many tests were performed by researchers to determine the amount of deposition and reduction of permeability but the boundaries in which the asphaltene deposited in oil or at the pore surface are not determined.

In this paper, series of tests are performed in order to determine the effect of asphaltene deposition on sandstone rock. Assuming negligible change of viscosity due to various concentrations of asphaltene added, results of laboratory tests performed using pre-separated asphaltene contents from crude oil are showed, to be sure that the first stage (if we divide it into precipitation from liquid phase and deposition on pore surface) of depositing is passed, n-hexane used to flocculate asphaltene particles. To generate reliable data on formation permeability damage due to asphaltene deposition, several dynamic displacement experiments with oil asphaltene content were conducted in various rates and concentrations.

These laboratory tests have shown evidence of core damage happening under dynamic flowing conditions. Data were plotted in order to determine the effect of permeability reduction with comparison to reference oil permeability. It shows a significant permeability reduction after flooding. The results have shown that removal and deposition processes occurred simultaneously and trends were similar to previous works where they follow a straight-line pattern except where removal occurs. The previous available models on CMG roughly matched the data.

The test results and data can be used in formation damage due to asphaltene deposition models for matching and checking models available in literature and commercial softwares.
Joint Development of an Environmentally Acceptable Ester-Based Drilling Fluid
Authors: Amin R. A. , Clapper D. K. , Norfleet J. E. , Otto M. J. , Xiang T. , Hood C. A. , Goodson J. E. , Gerrard D. P.
Published: July 2010

Drilling through highly sensitive shale areas with challenging well profiles, including highly deviated and extended long reach, require the use of an oil-based mud (OBM). However, environmental legislation restricts the discharge of drilling waste/cuttings especially when the cuttings are contaminated with OBM. Therefore, a more environmentally acceptable drilling fluid system is required. The palm oil derivative drilling fluid system is one of the alternatives to meet the challenge.

Joint development was carried out in Kuala Lumpur and Houston with the goal to develop a high-performance synthetic-based drilling fluid. Three esters of interest were evaluated for possible use as the external phase of an invert emulsion. The testing conducted with the esters included elastomer compatibility testing, base oil viscosity, drilling fluid properties and Leptocheirus 10-day bioassays. A series of tests were also conducted with the blend of ester and paraffin and a blend of ester and mineral oil. Fluids were successfully formulated with a minimum number of components including organophilic clay, emulsifier, calcium chloride brine and barite. Several systems were tested for property changes in response to weight up or contamination with simulated drill solids, seawater or cement. Most systems exhibited acceptable changes in fluid properties. Fluids were observed to be stable up to the test aging temperature of 250°F (121°C). Based upon the tests completed, a more environmentally friendly synthetic oil-based drilling fluid has been developed.
Designing of Ultralight Slurry for Liner Cementation: Case Study
Authors: Nabi A. G. , Qureshi S. A. , Arif M. U.
Published: July 2010

Yaqut -1 well is located in Safed Koh Lease of Dewan Petroleum Pvt Ltd. The well was a Re-entry Well. Original well was drilled in 1984 and was classified as dry well.

Dewan Petoleum decided to re-enter the same well and drill down 1356m of 6" hole to test the potential of Chiltan limestone as primary target and Sembar and Lower Goru sands as secondary targets.

The Well is located in tectonically stressed/ active area with fractured formations with under-hydrostatic head. This is the cause of severe losses even at Normal Hydrostatic head. The same case happened also with offset well drilled to same depth. Cementation of liner/ casing was very poor which generated many operational issues in post-completion life of the well.

Keeping this in mind, we worked on different options of slurry design, mechanical barication i.e use of External Casing Packers, Expandable Rubber Sleeves etc and multistage cementation. The geometry of 6" hole of about 1356m long interval and 5" Liner length of 2278m, did allowed only to manipulate with Slurry weights and discarded all other options. The final option of 7.9ppg Slurry was finalized after authentic Lab test results and ensuring slurry properties.

Designed slurry was pumped with only 28bbl loss out of 140bbls. The USIT Log was carried out which showed best cementation results.

This paper will discuss in detail the comparison of cementation results of Yaqoot-1 well with offsets. Detailed discussion of slurry designs considered for subject well along with application in under-hydrostatic fractured formations. Lab results of slurry design and USIT Logs have also been discussed in this paper to conclude the strategical justification Ultra Light Slurry Design.
Waterflood Tomography: Mapping High Contrast Permeability Structures Using Injection/Production Data
Authors: Lin Yenting , Ortega Antonio , Nejad Amir Mohammad , Ershaghi Iraj
Published: July 2010

The paper presents a novel method to detect the existence and determine the orientation of high permeability channels between injection and production wells in a waterflood. We apply the concept of transmission tomography and model a waterflood reservoir by considering water injection rates as inputs and measured production rates as outputs. We solve the inverse problem, in which the goal is to determine the existence and location of high permeability channels in the field by measuring the lag time in response to the variation in the injection rate. The main advantage over other methods (e.g., tracer testing) is that this technique can be applied without significantly affecting daily operation.

We show that the lag times at the producers can be estimated by monitoring production rates, given that known time-varying injection rates are applied. We propose a mixture model to characterize the lag time for each injector-producer pair, where the system is initialized by assuming that multiple candidate fractures exist. Our algorithm iteratively modifies the length, orientation and location of each high permeability candidate in order to match the measured response time between wells. It is well known that the solution may not be unique if we only have limited measurement data. Thus, in order to choose between possible models, we propose to use the "total length" of high permeability channels as regularization metric. Our method will select the model that fits the measured lag time with minimum total high permeability channel length. It is also possible within our framework to adjust the regularization so that it takes into consideration other type of prior information, e.g., preferred orientation known to exist in a given field.

To validate our approach, we use a commercial simulator to test a synthetic line drive and a 5-spot waterflood. In the first case, we test a five spot with hydraulic fracture located in the central production well.

In the second case, we test a single fracture with 45 degree orientation located between rows of producers and injectors. Our results show that our method can provide very accurate estimates of fracture orientation, with decreased uncertainty as the well density in the field increases.
Application of Neural Network Model for Prediction of Asphaltene Precipitation
Authors: Abedini A. , Ashoori S. , Saki Y.
Published: July 2010

The Precipitation and deposition of crude oil polar fractions such as asphaltenes in petroleum reservoirs reduces considerably the rock permeability and the oil recovery. Therefore, it is of great importance to determine "how" and "how much" the asphaltenes precipitate as a function of pressure, temperature and liquid phase composition. In present work, an Artificial Neural Network (ANN) model was designed and applied to predict the amount of asphaltene precipitation at a given operating condition. An extensive experimental data for the amount of asphaltene precipitation at various temperatures (293-343 K) was used to create the input and target data for generating the ANN model. The predicted results of asphaltene precipitation from ANN model was also compared with the results of some proposed scaling equations. The results revealed that scaling equations fail to predict the amount of asphaltene precipitation adequately for different ranges of temperature and dilution ratio, especially at lower values of dilution ratio. While an acceptable agreement between experimental data and predicted amount of asphaltene precipitation for all ranges of dilution ratio, solvent molecular weight and temperature was obtained through using ANN model.
Hierarchical Pixel-Based Geostatistical Modeling of Estuarine Reservoir Through Streamline Simulation in Ceuta-Tomoporo Field, West Venezuela
Authors: Acosta Alejandro
Published: July 2010

The geocellular models developed by geostatistical techniques are the key of the integrated studies of reservoirs because they are the link between the geological and dynamic models, where they must represent consistently the heterogeneities described by the geologists and geophysicists in the numeric simulation grid.

The study was developed in the B-4 Unit of the "B-Sup VLG-3729" reservoir, located in the off-shore and on-shore Ceuta- Tomoporo Field, west Venezuela. It is dominated by an estuarine sedimentary ambient, with an area above 32000 acres and a thickness of 500 feet. Contains an OOIP above 3 MMMSTB of medium gravity oil, and up-to-date 100 wells have been drilled.

In addition to the traditional stages required to build a geostatistical model, this case of study involved an evaluation of the dynamic response of several equi-probable geostatistical realizations developed by pixel-based algorithms like Sequential Indicator Simulation[3] (SIS) and Sequential Gaussian Simulation[3] (SGS), obtaining the statistical OOIP. Due to the large number of cells considered in the fine grid, a streamline was necessary instead of a finite differences simulator in order to run the model in a reasonable time. In this stage, it was also necessary to apply a conventional reservoir analysis, in order to represent its dynamic behavior.
Substantial Decrease in Subsurface Equipment Failures in a Mature Field in Western Venezuela
Authors: Baptista L. A. , Gomez C. I. , Balzan N. E. , Medina E. J. , Bravo B. J.
Published: July 2010

This paper presents the results of the implementation of several remedial actions to reduce the sucker rod pumped well failure frequency, during the 2006-2008 period in La Concepcion field, Western Venezuela. Before 2006, the presence of a pulling rig to put wells back into production was a constant.

Wells failed continuously caused by rod wear, sand production, paraffin deposition and also subsurface pump valves wear, resulting in a failure frequency of 0.810 failure/well-yr.

Sucker rod pumped wells have been produced from the shallow Eocene reservoir since 1924. The current average production rate is 30 BFPD per well and a low productivity index (around 0.09 BFPD/psi).

Continuous rod system was implemented to reduce failures related to rod wear. Other actions were artificial lift method change to plunger lift and chemical treatment improvement to control paraffin deposition. Furthermore, custom-made changes in pump materials components and accessories were necessary to control the consequences of sand production.

At the end, these changes have enabled Petrowayuu to reduce the Eocene reservoir wells failure rate from 0.810 failure/well-year to 0.361 failure/well-year, which represents a 55% failure reduction and savings of more than 1,700,000 USD/yr.
Water Handling Project at TSP, Trinidad
Authors: Rampersad K. , Lom S. , McLean H.
Published: July 2010

This Paper describes how it is possible to modify existing equipment and chemical treatment and effectively separate approximately 94% of water produced and treat it offshore. The aim is to separate water from oil on the platform abiding by environmental regulations and hence reduce operating costs with a defined budget. The engineering described is basically that of creating secondary and tertiary separation at each facility, improving chemical treatment and designing for redundancy and future production increases.
Dealing with the Challenges of Hydraulic Fracture Initiation in Deviated-Cased Perforated Boreholes
Authors: Fallahzadeh S. H. , Shadizadeh S. R. , Pourafshary P.
Published: July 2010

Hydraulic fracturing is an extensively valuable stimulation method in oil and gas wells, which are no more producing efficiently, to improve the recovery of hydrocarbon from the reservoirs. The challenge of fracture initiation pressure and near- wellbore fracture propagation is a complex problem especially in deviated and cased perforated holes. In this paper a computer model is developed for estimating the initiation pressure as well as the orientation geometry of the fracture in the perforations around the borehole.

Deviated well drilling techniques are used commonly all over the world to develop the reservoirs which are not well produced by vertical wellbores. Most of such wells are perforated after they have been cased and cemented. The existence of the casing along with the cement properties, considerably influence the stress distribution around the wellbore. In this model analytical equations are applied along with the numerical methods to analyze the stress profile around a cased cemented borehole with arbitrary inclination and azimuth. In addition, new analytical formulas are derived and applied to simulate the stress profile around the perforations, taking account of cement sheath and formation mechanical properties as well as perforation gun orientation.

Results of this model are presented using common parameters at different in situ stress regimes, cement and rock properties, and also perforation and well trajectory limits. Wellbore tensile zone, fracture initiation pressure, and investigating the micro- annulus creation are among the main outputs of this modeling. It is concluded that, optimum well inclination and azimuth in conjunction with perforation orientation as well as cement properties can be derived at various stress regimes. As a result lower fracture initiation pressure with better fracture orientation geometry in terms of linking up of small fractures and less fracture tortuosity can be achieved. The significance of this model is its ability in analyzing the stress profile along the perforations tunnel and casing cement sheath, so more realistic fracture initiation pressure and near-wellbore fracture geometry would be anticipated.
Trinidad Columbus Basin Petrophysics Field Study Part 1: Volume of Shale and Porosity
Authors: Ali-Nandalal J. , Smith D. R. , Ramoutar R. , Teelucksingh S.
Published: July 2010

A Petrophysical Refresh of the bpTT fields in the Columbus Basin in Trinidad has been carried out. The objectives of the Refresh were to provide continuity and consistency in petrophysical interpretations in this mature basin where over the years multiple vendors and differing interpretational approaches have been employed.

In an effort to create a more robust core data set, data gaps were identified in the existing core analyses and supplemental analysis performed. The core data set was expanded to include additional porosity and permeability measurements at net mean stress, laser particle size analysis was conducted on shaley intervals from 4 wells to confirm volume of shale method.

New models were developed for volume of shale, porosity and net cut-offs and each of these models were calibrated against the robust core dataset. A curvilinear volume of shale was confirmed to be the most appropriate to estimate volume of shale for the bpTT fields. A total porosity model has been recommended, replacing the legacy effective porosity models. Core derived mini- permeability profiles were combined with core photos, and log-derived volume of shale and effective porosity log curves to explore the limits of what might constitute net.
An Innovative, Low-Cost Approach to Deriving Stress Conditions to Maximize Reserve Recovery in Unconventional Reservoirs
Authors: Kneedy Jason , Atteberry Jeff , Smith Charles H , Menendez Eli
Published: July 2010

Accurate well placement and spacing, especially when using horizontal wells, is essential for optimizing reservoir development and production. In order to develop such a plan, the production mechanisms governing the reservoir must first be fully determined. Several approaches and techniques have been used to achieve this objective. The capacity of the reservoir to deliver hydrocarbons to the horizontal well bore must be understood and defined by a technique that will enable intelligent construction of a reservoir management philosophy. A variation of as little as a 30 degrees from the optimum well bore direction can result in reductions of reservoir efficiency as much as 14%.

Fracture propagation achieves greater length and height when a borehole is oriented in the direction of the minimum stress. The orientation of the in-situ stress field is the critical information needed to achieve optimal placement of horizontal wells. Crossed-dipole sonic logs with directional information enable the magnitude and orientation of acoustic anisotropy to be determined, which provide representations of the in-situ stress field (Fogal 2002). After the direction of maximum horizontal stress is known, the well can be placed and the direction of the horizontal wellbore oriented to attain maximum reservoir exposure after fracture treatment. Compressional- and shear-wave slowness provided by the dipole sonic tool also enable the direct calculation of the rock mechanical properties that define fracture treatment initiation and propagation (Cipolla 1994).

Because the cost of acquiring of crossed-dipole sonic data can be prohibitive, an alternative, cost-effective method for acquiring the necessary data about the in-situ stress field orientation was evaluated. Wellbore elongation is an indicator of stress anisotropy. A directional package was added to an openhole multiarm caliper and the observed borehole deformation was evaluated to determine the implied direction of the horizontal stresses. This defined regional horizontal stress information was then used to orient the horizontal component of each well. This paper compares the results derived from the examination of borehole elongation with the more precise data derived from the dipole sonic logs. This technique provides a cost-effective alternative for determining the orientation of the stress anisotropy in unconventional reservoirs.
Effect of Gas Recycling on the Enhancement of Condensate Recovery in an Iranian Fractured Gas/Condensate Reservoir
Authors: Moradi B. , Tangsirifard J. , Rasaei M. R. , Maklavani A. Momeni , Bagheri M. B.
Published: July 2010

Gas condensate reservoirs have complicated fluid flow and thermodynamic processes. The reservoir temperature of these systems lies between the critical point and cricondentherm. As reservoir pressure decreased, the gas condensate system exhibits a dew point. As pressure is reduced, liquid condenses from the gas to form free liquid in the reservoir. The condensate is deposited at such low liquid saturation that is usually trapped by surface tension forces, is therefore immobile, and cannot be produced. Condensate liquid builds up near wellbore causing a reduction in gas permeability and gas productivity. The injection of dry gas into a retrograde gas condensate reservoir helps in vaporizing the condensate and increases its dew point.

This study prepared an insight into the mechanism of gas injection process in reducing gas-well productivity losses due to condensate blockage in the near wellbore region. The main goal of this work is to investigate the lean gas recycling into the reservoir to enhance condensate recovery and to prevent permeability reduction. In this work, these subjects were studied: fluid phase diagram changes in gas condensate reservoir, initial gas in place and prediction of the amount of condensate, recovery factor evaluation at different scenarios (Natural depletion and gas injection), implementation of gas recycling to enhance recovery and comparison of this method with CO2, N2 and methane injection.

This research was done on a retrograde gas condensate reservoir through compositional simulator. Five possible scenarios: natural depletion, gas recycling, methane, CO2 and N2 injection, were compared. In each scenario, changes in reservoir fluid composition after injection were investigated. Results indicated that CO2 injection yields better recovery that others and methane injection has the least recovery.
Study of Various Water Alternating Gas Injection Methods in 4- and 5-Spot Injection Patterns in an Iranian Fractured Reservoir
Authors: Darvishnezhad M. J. , Moradi B. , Zargar G. , Jannatrostami A. , Montazeri G. H.
Published: July 2010

In the common methods of water and gas injection, high and unsuitable mobility ratio within the injected fluid and the oil in the reservoir, leads to viscose fingering and reduction of sweep efficiency. It was originally intended to improve sweep efficiency during gas flooding, with alternating slugs of water and gas (WAG injection) designed by and large to follow the same route through the reservoir.

WAG injection has been widely applied since the late 1950s. The typical improved oil recovery (IOR) potential for WAG injection when compared with water injection is quoted in the literature at 5-10%. In this method, injection of water slugs followed by gas, leads to triple region, increase the contact level of injected fluid and reservoir, stable the movement front, and finally increase the recovery. However, depend on the conditions, type and pattern of injection, improvement of recovery is variable and different. WAG injection in five methods, immiscible, miscible, hybrid, simultaneous and selective simultaneous.

In this work, scenarios of WAG injection such as Immiscible WAG (IWAG), Hybrid WAG (HWAG), Simultaneous WAG (SWAG) and Selective Simultaneous WAG (SSWAG) and water and gas injection are compared to specify the appropriate injection method. Then ultimate oil recovery, residual oil saturation, daily and total oil production are compared in these scenarios. Also these scenarios in four and five spot injection patterns were compared.

Results indicated that, SSWAG injection has the higher oil production and lowest residual oil saturation. In addition, among these scenarios, SSWAG in 4-spot pattern had the highest recovery and daily oil production. 4-spot pattern had the higher recovery and lower residual oil saturation than 5-spot pattern, so adding the number of wells could not raise the recovery.
An Improved Triple Porosity Model for Evaluation of Naturally Fractured Reservoirs
Authors: Al-Ghamdi Ali , Chen Bo , Behmanesh Hamid , Qanbari Farhad , Aguilera Roberto
Published: July 2010

Many naturally fractured reservoirs are composed of matrix, fractures and non-touching vugs (it can also be any other type of non- connected porosity that can occur, for example, in intragranular, moldic and/or fenestral porosity). An improved triple porosity model is presented that takes into account these different types of porosities. The model can be used continuously throughout a reservoir with segments composed of only matrix porosity, or only matrix-fractures, or only fractures-vugs, or the complete triple porosity system.

The model improves a previous triple porosity algorithm by handling rigorously the scale associated with each, matrix, fractures and vugs. This permits determining more realistic values of the cementation or porosity exponent, m, for the composite system and consequently improved values of water saturation and reserves evaluations. The values of m for the triple porosity reservoir can be smaller, equal to, or larger than the porosity exponent of only the matrix blocks, mb, depending on the relative contribution of the vugs and fractures to the total porosity system.

It is concluded that not taking into account the contribution of matrix, fractures and vugs in the petrophysical evaluation of triple porosity systems can lead to significant errors in the determination of m, and consequently the calculation of water saturation, hydrocarbons in place, recoveries, and ultimately poor economic evaluations, either too pessimistic or too optimistic. This is illustrated with a couple of examples from Middle East carbonates.
Cumulative Gas Production Distribution on the Nikanassin Tight Gas Formation, Alberta and British Columbia, Canada
Authors: Solano Nisael , Zambrano Liliana , Aguilera Roberto
Published: July 2010

271 wells producing exclusively from the Nikanassin and equivalent Formations in a very large area of over 15,000 square kilometers in the Western Canadian Sedimentary Basin (WCSB), Alberta and British Columbia, Canada, have been evaluated with a view to determine the distribution of cumulative gas production and the possibilities of intensive infill drilling.

The Upper Jurassic to Lower Cretaceous Nikanassin formation is generally characterized as a tight gas formation with low values of permeability (typically a fraction of millidarcy) and low porosities (usually less than 6%). It is likely that natural microfractures and slot pores dominate the productivity of the formation. The study area was divided into 6 smaller narrow areas (A to F) approximately parallel to the NW-SE trending thrust belt of the Canadian Rocky Mountains. Area ‘A’ is located to the west of the deformation edge, area ‘B’ is on the deformation edge, and areas ‘C’ to ‘F’ are located to the east. Area ‘C’ is the deepest and closest to the thrust belt, whereas area ‘F’ is the shallowest and furthest from the thrust belt.

Cumulative production characteristics within each area were evaluated with a variability distribution model (VDM) developed recently for naturally fractured reservoirs. The evaluation of each one of the 6 areas (271 wells) resulted in coefficients of determination, r2, greater than 0.99 in all cases. The results indicate that the gas cumulative production distribution per well is more homogeneous along the deformation edge (area B), where 80% of the wells contribute approximately 50% of the cumulative production. The highest heterogeneity was found in area F (the shallowest) with 80% of the wells contributing only 25% of the cumulative gas production. Areas A, B, D and E have more or less the same distribution with 80% of the wells contributing between 35% and 45% of the cumulative gas production. Preliminary, there is an association between the cumulative production distribution and lateral variations of borehole breakouts in the Nikanassin formation on a transect perpendicular to the deformation belt of the WCSB.

Analysis of the distributions leads to the conclusions that the Nikanassin is a very heterogeneous formation and that there is significant potential for massive drilling to efficiently drain the formation. The possibilities of horizontal wells and multi-stage hydraulic fracturing jobs are being investigated at this time.
Successful Coiled-Tubing Drilling-Hole Enlargement Improves Production
Authors: Ortega R. , Kowalski R. , Escobar J. , Garcia R.
Published: July 2010

Schlumberger coiled-tubing drilling (CTD) initiative was implemented in west Venezuela (Lake Maracaibo) in 1993 from a CTD Barge. This purpose-built barge was assembled to minimize the risk to personnel and equipment while drilling superficial zones for a Venezuelan operator where the presence of shallow-gas sands makes safety a priority (Adamson S.J. 1994). To date, this project has drilled over 300 wells.

Nowadays, the operator has new challenges: to continue draining the remaining oil reserves, new process and designs are required to successfully achieve their expectations.

The new CTD challenge is focused on the Field C and Field D and more specifically the Eocene primary target zone and, as a secondary target zone, the Miocene. These zones are separated by a discordance1. From the discordance and around the upper Eocene, formation pressure is significantly reduced (around 400 psi lower) with respect to the Miocene age reservoir pressure. This issue represents a serious challenge during the drilling phase because fluid losses might be present when crossing the discordance zone. To address this situation, an intermediate casing can be placed at the end of Miocene; however, this will limit the subsequent completion by reducing the final tubing size and therefore, affecting the potential well production.

The proposed solution is based on drilling a larger surface hole, 14¾ in., and setting larger surface casing, 10¾ in., allowing the operator to run larger completions (intermediate and/or production casings). If isolation is required across the discordance, this design will provide an optimal completion without compromising the well's oil production.

Several studies and analysis were implemented to adapt the design and execution phase with the new requirement from the operator and the operating capabilities of CTD Barge.

To date, four wellbores have been successfully enlarged to 14¾ in., completed with 10¾-in. casing, and cemented. Subsequently, a conventional drilling rig / barge has been used to complete these wells to their production phase, and represent an incremental production gain, estimated at over 150 bbl/day of oil for the four wells.
A New Approach to Low-Cost, High Performance Chemical Flooding System
Authors: Elraies K. A. , Tan I. M. , Awang M.. , Fathaddin M. T.
Published: July 2010

This paper presents a new Acid-Alkali-Surfactant (AAS) flooding formulation as an alternative to conventional alkaline/surfactant/polymer (ASP) process. It is a cost-effective formula that is able to overcome precipitation problems prevalent with ASP flooding when natural sea water was used. The acid was evaluated in an AAS formulation using sodium carbonate and introducing a new polymeric surfactant derived from Jatropha oil. The feasibility of applying the new AAS formula was demonstrated by a series of experiments involving fluid compatibility test with natural sea water having a large quantity of divalent metal cations, interfacial tension between Angsi crude oil and AAS solution, surfactant adsorption, and core flood using Berea core samples. The acid effectively prevented divalent metal cations from precipitating and all solutions remained clear for 90 days at 90°C. The optimum acid concentration was found to be proportional to alkali concentration in the ratio of 1.66:1. A combination of the new system was found to significantly reduce the IFT and the adsorption level of the surfactant. The best chemical concentrations were then validated in core flood tests using various alkali and surfactant concentrations. The optimum alkali and surfactant concentrations were confirmed as 0.6% and 0.6% respectively. Using the optimum concentrations, another series of core flood tests were conducted by changing the injection volume. Only a small incremental recovery was obtained with slugs higher than 0.5 PV. Injection of 0.5 PV of the formulated slug followed by chase water produced an additional 18.8% OOIP over water flood, accomplishing a total oil recovery of 77.3% OOIP. This makes the new AAS formula an attractive and cost-effective agent for CEOR particularly for offshore field application.