bluuebunny/crossref_metadata_2025_split huggingface dataset:
What Is Stimulated Reservoir Volume?
Authors: Mayerhofer M.J.. J. , Lolon E.P.. P. , Warpinski N.R.. R. , Cipolla C.L.. L. , Walser D.. , Rightmire C.M.. M. 
Published: March 2010

Summary
Ultralow-permeability shale reservoirs require a large fracture network to maximize well performance. Microseismic fracture mapping has shown that large fracture networks can be generated in many shale reservoirs. In conventional reservoirs and tight gas sands, single-plane-fracture half-length and conductivity are the key drivers for stimulation performance. In shale reservoirs, where complex network structures in multiple planes are created, the concepts of single-fracture half-length and conductivity are insufficient to describe stimulation performance. This is the reason for the concept of using stimulated reservoir volume (SRV) as a correlation parameter for well performance. The size of the created fracture network can be approximated as the 3D volume (stimulated reservoir volume) of the microseismic-event cloud. This paper briefly illustrates how the SRV can be estimated from microseismic-mapping data and is then related to total injected-fluid volume and well performance. While the effectively producing network could be smaller by some proportion, it is assumed that the created and the effective network are directly related. However, SRV is not the only driver of well performance. Fracture spacing and conductivity within a given SRV are just as important, and this paper illustrates how both SRV and fracture spacing for a given conductivity can affect production acceleration and ultimate recovery. The effect of fracture conductivity is discussed separately in a series of companion papers. Simulated-production data are then compared with actual field results to demonstrate variability in well performance and how this concept can be used to improve completion design, well spacing, and placement strategies.
Gas/Condensate Relative Permeability of a Low Permeability Core: Coupling vs. Inertia
Authors: Jamiolahmady M.. , Sohrabi M.. , Ghahri P.. , Ireland Shaun 
Published: March 2010

Summary
Flow around the wellbore of gas/condensate systems, when pressure drops below dewpoint, is controlled by complex interaction of capillary, viscous, and inertial forces. Hence, it is challenging to determine accurately gas/condensate relative permeability (kr) that is affected by the relative impact of these competing forces.
There are a number of reports demonstrating kr of high permeability rocks affected by both coupling [the increase of kr as velocity increases and/or interfacial tension (IFT) decreases] and inertia (i.e., the reduction of kr as velocity increases) for these low IFT systems. However, there is little information on this subject for low-permeability rocks.
In this work, different series of steady-state k r values for a 3.9- md sandstone reservoir rock with a porosity of 6% are reported. These k data sets have been measured experimentally at three IFT levels below 1 mNm-1 and five velocity levels below 200 md-1.
The results indicate that at the highest IFT, inertia is dominant at low condensate-/gas-flow-rate ratio(CGFR) at test conditions, whereby kr reduces with increasing velocities. At higher CGFR, an increase in kr is observed because of the dominant effect of coupling. At lower IFT, the negative impact of inertia on k as velocity increases is observed at all CGFR. Jamiolahmady et al. (2008) have recently reported kr of highly conductive propped fractures showing a more pronounced effect of inertia at lower IFT, but this is the frrst report of such behavior for low permeability rocks. These k r measurements are also compared with the corresponding predicted k using the generalized kr correlation recently developed by Jamiolahmady et al. (2009). The correlation expresses the combined effect of coupling and inertia with universal parameters. The unique contribution of inertia, as observed in the experiments and predicted by the correlation, is attributed mainly to the high single-phase inertial factor of the rock and fluid properties of the flowing phases.
Using Distributed Volumetric Sources to Predict Production from Multiple-Fractured Horizontal Wells Under Non-Darcy-Flow Conditions
Authors: Amini Shahram , Valkó Peter P. 
Published: March 2010

SummaryThe method of distributed volumetric sources (DVS) has been applied to predict gas production from a horizontal well with multiple transverse fractures in a bounded reservoir. Combining the quasianalytical DVS method, which provides us with the opportunity to predict pressure and production behavior of complex well/fracture configurations, with non-Darcy flow in the fracture enables us to calculate the optimum configuration in terms of the number and dimensions of fractures per well for a certain amount of proppant of a given type. The method is applied to an example case of a tight gas reservoir to maximize the production performance of this complex well/fracture configuration. Comparing results with and without inclusion of the non-Darcy effect in the fracture shows that a decrease in production occurs because of non-Darcy flow in all cases. However, a systematic screening of a realistic set of well/fracture configurations reveals that the detrimental effect of non-Darcy flow can be substantially compensated for by selecting the right number of fractures and shifting the fracture dimensions in favor of thicker fractures. While a simultaneous decrease in optimum lateral (and vertical) extension is necessary, it has limited effect on productivity. The simplicity, robustness, and small computational demand of the model allow seamless integration with external economic and operational constraints, providing a tool to screen and optimize a large set of possible configurations most suited for the development of economically marginal fields.
Modeling of Sand Cleanout With Foam Fluid for Vertical Well
Authors: Li Songyan , Li Zhaomin , Lin Riyi , Li Binfei 
Published: March 2010

Summary
Foam has proved to be effective and economical in underbalanced operations and is gaining wider applications in many areas. Foam fluid has low density and high blocking ability. It can effectively reduce leaking of fluid into formation in low-pressure wells, protecting the oil formation and improving sand-cleanout efficiency. According to energy-conservation equations, mass-conservation equations, and momentum-conservation equations, a mathematical model for sand cleanout with foam fluid was established that considers the heat transfer between foam in the annulus and foam in the tubing. The model was solved by numerical method. Distributions of foam temperature, foam density, foam quality, pressure, and foam velocity in the wellbore were obtained. Calculation results show that temperature distribution is affected greatly by thermal gradient. As the well depth increases, foam pressure and foam density increase and foam quality and velocity decrease. Foam velocity at the well bottomhole is the minimum. Friction pressure loss of foam is less than that of water at the same volume flow rate. Site applications show that sand cleanout with foam fluid can prevent fluid leakage effectively. It can avoid damage of sealing agents and reduce pollution. The average relative error and standard deviation between model and field data on injection pressure are–0.43 and 2.55%, respectively, which proves the validation of the mathematical model.
Effect of Calcium and Iron (II) Ions on the Precipitation of Calcium Carbonate and Ferrous Carbonate
Authors: Alsaiari H.A.. A. , Kan A.. , Tomson M.B.. B. 
Published: March 2010

Summary
This work was intended to study the interaction between ferrous-iron and calcium ions simultaneously toward carbonate ions in supersaturated solution in a continuous stirred tank reactor (CSTR) and to establish an acceptable experimental design as a preparation step to study the kinetics of other types of ferrous iron salts. The experiments were conducted in 0.5 M NaCl solution at 55°C. The pH values were between 6.2 and 7.8. It was found that calcium ions have a strong influence in increasing the solubility of iron carbonate. On the other hand, ferrous iron did not affect the solubility of calcium carbonate significantly. This might be caused by increasing the stability of ferrous iron carbonate complexes in the presence of calcium. Also, the molar ratios of calcium to iron in the solution were compared with their molar ratios in the precipitated salts. It was found that the relation was greater than unity; Rsolid/Rsolution = 2.39. Thus, calcium carbonate has a preference to precipitate. This result seems to be in agreement with water dissolution rates of divalent ions and also with reaction-rate constants of iron carbonate and calcium carbonate reported in the literature.
A Successful Application of Fiber-Optic-Enabled Coiled Tubing With Distributed-Temperature Sensing Along With Pressures To Diagnose Production Decline in an Offshore Oil Well
Authors: Parta P.E.. E. , Parapat A.. , Burgos R.. , Christian J.. , Jamaluddin A.. , Rae G.. , Foo S.K.. K. , Ghani J.. , Musa M.. 
Published: March 2010

Summary
In this paper, we present a field example where pressure and distributed-temperature measurements enabled understanding of reservoir characteristics and fluid movement causing production hindrance in an offshore horizontal well. The field example has a horizontal well in the South China Sea that was completed as an openhole monobore oil producer using a slotted liner. The well began production with an initial oil rate of 1,800 B/D. Oil production quickly dropped to 1,000 B/D and gradually declined to 200 B/D. During this period, the gas/oil ratio (GOR) steadily increased from 200 scf/bbl to 2,200 scf/bbl. To arrest production decline, a chemical treatment was conducted to remove suspected emulsions and polymers assumed to have been deposited during drilling. Immediate post-treatment production increased to 3,700 B/D, but dropped dramatically and stabilized at pretreatment rates soon after. Formation of emulsions and asphaltenes were believed to be the cause of the production decline. However, with inadequate information, the diagnosis was inconclusive. Consequently, another chemical treatment was conducted and this time, a fiber-optic-enabled coiled-tubing (CT) string along with real-time bottomhole-pressure and temperature gauges were used to acquire distributed temperatures and pressures of the entire horizontal section of the wellbore.
Results of the pressure survey revealed that the well was receiving insufficient pressure support from the water injector, which was causing gas-cap expansion. The distributed-temperature survey indicated excessive gas production from the toe of the horizontal section as a result of this expansion, thus limiting liquid production. The combination of gas rates with oil and water production has also created tight emulsions, further hindering production performance. It was concluded that the high gas production from the toe could not be selectively shutoff or controlled in the horizontal openhole slotted-liner completion to perform an effective stimulation program and treat the tight viscous emulsions.
Polymer Flooding in Unconsolidated-Sand Formations: Fracturing and Geomechanical Considerations
Authors: Khodaverdian Mohamad , Sorop Tibi , Postif Sophie , Van den Hoek Paul 
Published: March 2010

Summary
A study was carried out to determine the geomechanical effects of polymer flooding in an unconsolidated-sand reservoir. The work involved laboratory-scale polymer injections in unconsolidated- sand blocks to identify the injectivity mechanisms, numerical analyses for fracture prediction, and geomechanical modeling of the formation to examine the potential of shear failure and containment loss during flooding.
Laboratory tests under polyaxial conditions indicate that nearwellbore fracturing and permeability increase in unconsolidated sands occur at net injection pressures limited to 2.0 MPa. These findings were applied to fracture modeling. Geomechanical modeling suggests large-scale shear failure in the sand and in the bounding shale during polymer flooding. These are expected to affect both the fracture containment and the vertical-hole integrity. Finally, fracture predictions underscore the importance of the geomechanical considerations on determining the fracture dimensions and containment. Sensitivity analyses also point to the significance of binding several key parameters for fracture prediction. These include sand shale stress contrast, fluid quality and total-suspended-solids (TSS) content, fluid rheology and effective viscosity in the formation, and the filter-cake properties in the presence of polymer.
This paper provides a geomechanical perspective on the generally complex problem of polymer flooding in unconsolidated formations containing viscous oil. The work also offers some insights into the critical issues that must be examined in such situations to avoid catastrophic failures. It highlights the existing technological gaps in the current predictive capabilities.
Rapid Prediction of Carbon Dioxide Adsorption Isotherms for Molecular Sieves Using Simple Correlation
Authors: Bahadori Alireza , Vuthaluru Hari B. 
Published: March 2010

Summary
Carbon dioxide (CO2) emission from burning fossil fuels has been identified as the major contributor to the increase in atmospheric CO2 levels that can potentially lead to global climate changes. Among main methods that are being developed for CO2 capture and separation (CCS), CO2 adsorption is of great interest because of its low energy consumption, low equipment cost, and ease of application. In this work, a new simple-to-use correlation, which is easier than current available models involving a large number of parameters and requiring more-complicated and longer computations, is presented to predict accurately the CO2 adsorption isotherms for a molecular sieve as a function of temperature and CO2 partial pressure. This correlation predicts the CO2 adsorzption isotherms for CO2 partial pressures and temperatures up to 120 kPa and 470 K, respectively. The promising method to develop correlation for accurate prediction of CO2 adsorption isotherms could be extended for CCS for the wide range of adsorbents, including various molecular sieves, simply by readjusting the tuned coefficients. The average absolute deviation between reported data and the proposed correlation is approximately 4%.
Retrofit Gas Lift System for Tension-Leg-Platform Wells
Authors: Babajide Abisoye , Hall Jim , Garrett Johnnie 
Published: March 2010

Summary
When oil wells can no longer flow naturally at the desired rate, artificial-lift methods are often employed. Most mechanical installations of artificial-lift equipment require a complete workover of the well, involving pulling the well apart and rerunning the completion with additional artificial-lift components. These methods can prove prohibitively expensive and/or risky, and they may not pass the economic hurdle for implementation. A tubing punch and packoff gas lift system, also known as an "econo-gas lift" or retrofit gas lift system, may provide a less risky and more economically viable means of bringing dead wells back on production or optimizing flowing wells. To the best of our knowledge, the use of retrofit gas lift systems has been untested in a tension-leg-platform (TLP) environment and poses a new set of challenges as compared to its use onshore or in shallow-water locations. A case of the gas lift retrofit of an oil well on a TLP in the Gulf of Mexico (GOM) demonstrates the usefulness of the proposed method. This paper shows how a retrofit gas lift system was used for capturing remaining reserves from a loaded TLP well. The specific case relates to the Shell Ursa A9 well, and this paper presents the new technologies employed and the successes and challenges associated with bringing the well back on production.
Integrated Data Analysis and Dynamic Fracture Modeling Key To Understanding Complex Waterfloods: Case Study of the Pierce Field, North Sea
Authors: Hustedt B.. , Snippe J.R.. R. 
Published: March 2010

Summary
The performance of many waterfloods [and enhanced-oil-recovery (EOR) schemes] is characterized by fluid injection under fracturing conditions. Especially when the geology is complex and the mobility of the reservoir is low, induced fractures can be of the same order as the well spacing, which has a significant (in general undesired) impact on both areal sweep and vertical conformance. Therefore, fluid injection needs to be actively managed and surveyed in order to design an appropriate injection strategy over time.
We have analyzed historical injection/production-test, injection step-rate-test, and falloff (FO) test (FOT) data of an existing complex waterflood in the Pierce field, North Sea. The mental subsurface model that emerged from this data analysis was developed further through a series of dynamic fracture-propagation simulations. While the data analysis was a relatively standard procedure, the fracture-modeling part was far from trivial and included simulations using a standalone fracture modeling tool and a more sophisticated coupled dynamic fracture-propagation reservoir simulator, both being in-house software tools.
The combined analysis was used to develop a better understanding of the waterflood performance. The main improvement compared to previous work was the integration of the data analysis and the dynamic modeling work rather than looking at each data source individually. In combination, a consistent explanation of the observed reservoir behavior was achieved. This has resulted in changes in the day-to-day water injection management and is expected to play a key role in longer-term development strategies
Understanding Volumetric Sweep Efficiency in SAGD Projects
Authors: Baker R. , Fong C. , Bowes C. , Toews M. 
Published: March 2010

Abstract
An understanding of volumetric sweep and capture efficiency are critical to optimizing SAGD projects. Capture efficiency refers to how much mobilized and heated oil is actually produced. Volumetric sweep efficiency can be estimated reasonably well for SAGD pilots having an abundance of information. A rich data set may include geological, petrophysical, production, injection, pressure, temperature observation and 4D seismic data. With this information, excellent insight into steam chamber development can be assessed. However, determining volumetric sweep and op­timal strategies is a problem where data are sparse.
This paper summarizes analytical SAGD surveillance methods that estimate volumetric sweep and presents a work flow that can help optimize SAGD processes with limited data.
Although the methods each have their assumptions and are not perfect, there is general agreement. The various techniques are corroborated using public core, injection/production, temperature observation and 4D seismic for the Surmont and Christina Lake pilot projects.
Introduction
Evaluating reservoir performance through the surveillance of production data is an excellent reservoir management tool. For waterflooding, this can be achieved through a conformance plot(1) that indicates how efficiently net water throughput affects recovery. Associating a water balance with an oil balance enhances the understanding of the influx/efflux of fluids and outer boundary losses out of zones. The plot works well for waterfloods because of the low compressibility of the fluids. For SAGD, a similar surveillance principle using abundant data is applied. However, a material balance alone is not definitive because SAGD is an energy-intensive process where steam is required to reduce the oil viscosity to a point where it will flow. Therefore, accounting for the energy within the SAGD process provides a different perspective for multiple geologies and heterogeneities.
Typical objectives of SAGD surveillance using production and monitoring data are to determine:
Original oil in place (OOIP)
Remaining oil in place (ROIP)
Mobile ROIP distribution and current condition (saturation, temperature and pressure)
Limiting factors in recovery
Potential improvements to economic oil recovery
Recovery profile and optimizing recovery factor
Operating strategies to achieve better volumetric sweep
Role of Asphaltene Precipitation in VAPEX Process
Authors: Haghighat P. , Maini B.B. 
Published: March 2010

Abstract
VAPEX (vapour extraction) is an oil recovery process, in which heavy oil or bitumen is mobilized by injection of a low molecular weight hydrocarbon solvent and is drained by gravity to a horizontal production well. It has attracted considerable attention because of its potential applicability to problematic reservoirs and the potential for in-situ upgrading of heavy oil during the process.
Oil drainage rate under VAPEX is controlled by the viscosity of solvent diluted oil and can be affected substantially by de-asphalting. In-situ de-asphalting can be advantageous because it reduces the oil viscosity and leads to production of upgraded oil. However, the precipitated asphaltenes can also plug the pores of the formation and cause severe damage to the permeability.
The objective of the current work was to determine whether the beneficial effects of asphaltene precipitation would outweigh any formation damage. The effects of in-situ precipitation and deposition of asphaltenes on the rate of oil drainage and the quality of the produced oil under different operating conditions were experimentally evaluated. The experiments were conducted in a physical model, packed with 140 - 200 mesh sand, and propane was used as the solvent. The quality of the produced oil samples was evaluated through the SARA technique and viscosity measurements.
The experimental results show that the oil produced at higher injection pressures was substantially upgraded, but the viscosity reduction by asphaltene precipitation did not lead to higher production rates. The effect of viscosity reduction was negated by the accompanying damage to formation permeability. The huff and puff injection of toluene into the production well, to remove damage from the near well zone, was tried but proved to be ineffective. It led to production of oil with higher asphaltene content with no improvement in the rate of oil production compared to the lower pressure operation without asphaltene precipitation. However, co-injection of toluene with propane was successful in increasing the rate of production and the extent of upgrading obtained was encouraging.