bluuebunny/crossref_metadata_2025_split huggingface dataset:
Inferring Interwell Connectivity in a Reservoir from Bottomhole Pressure Fluctuations in Hydraulically Fractured Vertical Wells, Horizontal Wells, and Mixed Wellbore Conditions
Authors: Dinh Anh V , Tiab Djebbar 
Published: March 2013

Abstract
A technique using interwell connectivity is proposed to characterize complex reservoir systems and provide highly detailed information about permeability trends, channels, and barriers in a reservoir. The technique, which uses constrained multivariate linear regression analysis and pseudosteady-state solutions of pressure distribution in a closed system, requires a system of signal wells and response wells.
Signal wells and response wells can be either producers or injectors. The response well can also be either flowing or shut in. In this study, for consistency, waterflood systems are used in which the signal wells are injectors and the response wells are producers. Different borehole conditions, such as hydraulically fractured vertical wells, horizontal wells, and mixed borehole conditions, are considered.
Multivariate linear regression analysis was used to determine interwell connectivity coeffients from bottomhole pressure data. Pseudosteady-state solutions for a vertical well, a well with fully penetrating vertical fractures, and a horizontal well in a closed rectangular reservoir were used to calculate the relative interwell permeability. The results were then used to obtain information on reservoir anisotropy, high-permeability channels, and transmissibility barriers.
The following are some conclusions drawn from this study: (a) the interwell connectivity determination technique using bottomhole pressure fluctuations can be applied to waterflooded reservoirs that are being depleted by a combination of wells (e.g., hydraulically fractured vertical wells and horizontal wells); (b) wellbore conditions at the observation wells do not affect interwell connectivity results; (c) the complex pressure distribution caused by a horizontal well or a hydraulically fractured vertical well can be diagnosed using the pseudosteady-state solution and, thus, its connectivity with other wells can be interpreted.
Different synthetic reservoir simulation models are analyzed, including homogeneous reservoirs, anisotropic reservoirs, and reservoirs with a high-permeability channel, or a partially sealing barrier, or a sealing barrier.
Comparative Study Between Guar and Carboxymethylcellulose Used as Gelling Systems in Hydraulic Fracturing Application
Authors: Trabelsi Siwar , Kakadjian Sarkis 
Published: March 2013

Abstract
Guar gum and its derivatives are the most frequently used thickening agents in hydraulic fracturing. They account for possibly 90% of all gelled fracturing fluids. Carboxymethylcellulose (CMC) has little use today in hydraulic-fracturing applications. Due to uncertainity in guar availability, CMC is being recommended as an effective polymer alternative in hydraulic-fracturing applications. In order to evaluate this option, a comparative study was conducted between guar and CMC performance as gelling agents in hydraulic fracturing.
CMC can be an effective alternative to guar and as this study illustrates can minimize formation and proppant pack damage. Furthermore, the critical overlap concentration, C* was determined as an indicator of crosslinkability at low polymers concentration for both guar and CMC.
This study was also conducted in order to evaluate the effect of several breakers (ammonium persulfate, sodium persulfate and enzymes) on linear polymer and crosslinked gel systems degradation. Viscosity, particle size distribution and regain conductivity were measured as a function of breaker type and concentration. Design schedules of hybrid fracturing jobs performed with CMC and guar in similar completion conditions in the Permian Basin were reported.
Matrix Stimulation: An Effective One-Step Sandstone Acid System
Authors: Gomaa Ahmed M. , Cutler Jennifer , Qu Qi , Boles Joel , Wang Xiaolan 
Published: March 2013

Abstract
Sandstone acid systems, which are composed of HCl and HF, are commonly used to remove the formation damage in sandstone reservoirs. However, to perform any treatment using these acid systems, a preflush and/or a postflush of HCl plain acid must be injected to eliminate CaF2 precipitation and secondary precipitation. In this study, a new sandstone acid formulation was developed that can be used as a one-step sandstone acid system (OSSA). This system eliminates the requirement of preflush and postflush HCl acid stages, reduces the treatment complexity, reduces the HCl requirements, and reduces the overall treatment/rig time.
A coreflood study was conducted using different sandstone cores at 180°F. In additional to quartz, the tested cores had varying amounts of clay mineral, feldspar, and carbonate. Consequently, they can be used to judge the performance of the new OSSA system.
Based on the experimental results, regular sandstone acid must be used with a preflush stage of HCl acid to maximize its performance and eliminate CaF2/MgF2 precipitation. The needs of the postflush stage must be confirmed as it can cause damage for sandstone that has HCl sensitive clay mineral. All selected one-step sandstone acid formulations (Acids A, B, C, and D) were able to successfully treat Bandera sandstone cores. For Bandera sandstone cores, increasing HCl/HF ratio increased the permeability enhancement and reduced the injected acid volume. Using the same acid volume and composition, a higher permeability enhancement was observed for the core that had less clay and carbonate content. Based on HCl:HF ratio and sandstone composition, a minimum acid volume is required to achieve a permeability enhancement. For the Bandera sandstone formation, only 8 PV of the OSSA system was required to achieve 26% permeability enhancement. However, for a Berea sandstone core that had less clay mineral, 4PV of OSSA system increased the permeability by 86%. The feldspar amount in the composition of sandstone can significantly impact the permeability enhancement of Acid C, while kaolinite amount has nearly no effect. A corrosion test was conducted at 180°F for 6 hr using a two pipe grades (Cr-13 and N-80). Two types of corrosion inhibitor were evaluated at different concentrations. All tested formulas had a very low corrosion rate (less than 0.03 lb/ft2). For both corrosion inhibitor types, corrosion rate was increased by reducing the HCl/HF ratio and/or inhibitor concentration.
An Offshore Field Development Plan to Optimize the Production System from the Reservoir to the Tank
Authors: Karimi Vajargah A. , Usman M. , Brito R. , Karami Mirazizi H. , Ettehadi Osgouei R. 
Published: March 2013

Abstract
To perform a successful optimization of large and complex production facility, there should be a good communication between engineers at different departments (Reservoir, Production, Geological, etc). However, as a common practice, their decision making process is separate from each other. This may result in under-designing such as flow bottlenecks or over designing, which imposes unnecessary expenditures. This lack of communication can be alleviated by coupling the reservoir flow model to the facility network by means of enhancements in software development that can perform networking analysis in an effective manner.
This paper presents a work methodology and recommendations through a case study to develop an offshore field that contains both heavy and medium oil. First, commercial software is utilized to build the model according to the input data. Subsequently, a development plan has been suggested for this field and number of wells to be drilled in the reservoir has been determined. Then sensitivity analysis is performed to find out the best possible scenario to produce from the field. Economical analysis is performed for each case to assure profitability.
According to the available recoverable reserves, a 13 year production plan is proposed (average of 7.46% per year). Simulation results indicate that by the proposed scenario at least 20% more of total recoverable reserves can be produced over this period. The highest oil rate is observed at the end of fourth year (98000 STB/d), when the field is mainly developed. This case study shows that complex production systems can be modeled by commercial software, which leads into better production forecasts. In addition, it can help us in selecting proper down-hole equipments and predicting the possible problems in each well (such as sand production or asphaltene deposition in this case).
Friction Reducers as Water Management Aids in Hydraulic Fracturing
Authors: Kolla Harsha , Watson Philip , Patel Aditya , Robinson Ronald , Jackson Logan , Nair Mohan 
Published: March 2013

Abstract
Hydraulic fracturing has transformed the American energy industry, allowing unprecedented access to shale oil and gas deposits. However, fracturing's demand for water has raised concerns across the country, particularly in water-stressed regions like Oklahoma and Texas. Additionally, costs for disposing flowback and produced water have risen and regulations have tightened. Water management is becoming a crucial part of pressure pumping.
Instead of paying to import fresh water and paying again to dispose of produced and flowback water, many operators are now seeking to blend fresh and flowback water, but this strategy has its own challenges. Flowback water can contain elevated levels of dissolved solids (particularly polyvalent cations), bacteria, and organics, which can impair conventional friction reducer performance. Additionally, chemicals used to remediate flowback water can potentially affect friction reducer performance.
In order to aid water management efforts, Kemira has developed a friction reducer platform that shows superior performance in flowback and produced water with TDS concentrations as high as 236,000 ppm. These emulsion polyacrylamides (EPAMs) have molecular weights in the range of 20 – 40 million Daltons and are compatible with other additives such as scale inhibitors and biocides.
Friction reduction measurements were performed using a laboratory-scale friction loop designed to simulate the turbulent flow conditions encountered during hydraulic fracturing. Flow rates of 30 gallons per minute were achieved in 0.5-in diameter tubing, resulting in Reynolds numbers of 150,000. The polymers provided friction reduction up to 65% in produced and flowback water, and maximum friction reduction was reached in 50 seconds or less in all cases. By comparison, conventional friction reducers dissolved in 120 seconds in high TDS waters and gave less than 20% friction reduction.
Measured Plunger Fall Velocity Used to Calibrate New Fall Velocity Model
Authors: Rowlan O.L. , McCoy J. , Lea J. , Nadkrynechny R. , Cepuch C. 
Published: March 2013

Abstract
Plunger fall velocities for various plungers have been measured in many different wells in the field and measured in a large scale well simulator. A new theoretical plunger fall velocity model has been developed. This model equates plunger fall velocity to be inversely proportional to a constant multiplied by the square root of the density of the gas the plunger falls through. The measured fall velocity at a specific pressure and temperature is used to calibrate the model, and then the model can be used to calculate fall velocity at other conditions for the same plunger or used to show how changing a feature like plunger weight can impact fall velocity. The model's predicted fall velocity for different types of plungers will be compared with measured fall velocities.
A large scale plunger lift well simulator was used to determine plunger fall behavior in clear PVC tubing through compressed air and through gas free water. The performance of 36 different types and metallurgies of plungers were measured. Both in the field and at the well simulator an acoustic instrument was effectively used to accurately measure plunger fall velocity.
All plungers have the same general trend of fall velocity; where the plunger fall velocity is fast at low pressure and slows at higher pressure. Construction features of plungers and well conditions impacting plunger fall velocities will be highlighted. Using published fall velocities to determine the shut-in time period for a particular plunger type but may not be accurate for a well, because well pressure significantly impacts plunger fall velocity. The knowledge of how various parameters impact plunger fall velocity allows the operator to determine if the plunger has reached the bottom of the tubing by the end of the shut-in period and then optimize the plunger lifted well using the shortest possible shut-in time to maximize liquid and gas production.
Examination of Treatment Connectivity between Granite Wash Layers Using Microseismic, Tracer, and Treatment Data
Authors: Crawford Elspeth M. , Tehan Bob , Launhardt Bob 
Published: March 2013

Abstract
Linn Energy employed adjacent laterals; the upper lateral targeting the Carr Granite Wash and the lower lateral targeting the Britt Granite Wash to determine if there was fracture stimulation overlap between the two intervals. It was known from geological analysis that the two zones were separated by a Clay rich interval (Caldwell section). The discussion deals with the fracturing between zones, and what type of communication remains after the stimulation treatment has been completed.
Various completion techniques were employed including Zipper Fracs, Volume adjustments, Perforation Density and phasing changes, and pump rate variations to determine if the fracture geometry would be affected by these changes. Treatment evaluations were done using the examination of Microseismic results in conjunction with pumping treatment data and pressure data from multiple offset locations.
This paper reviews the methodology employed as well as the results of pressure analysis and Microseismic mapping results to determine if the Caldwell barrier could be overcome by the Fracture Stimulation or if adequate drainage of both the Britt and Carr zones would require individual laterals.
Real-Time Data and Expert System Combine to Develop Artificial Lift Predictive Diagnostics
Authors: Blanckaert Thibault , Subervie Yves M 
Published: March 2013

Abstract
Electric submersible pumps (ESPs) and progressive cavity pumps (PCPs) are used as lifting methods in many oil fields to improve oil production. Downhole gauges are now installed on most of the ESPs and PCPs, providing relevant pressure and temperature measurements to assess pump performance and potential failures. The volume of high-frequency data overwhelms the capacity of most direct assessment methods based on human observation. To address this challenge, a method using a combination of signal processing tools together with an expert system has been developed to deliver a predictive diagnostic in real time.
The data acquired is fed into a signal processing module to analyze and highlight trends and patterns. This module, based on Bayesian theory, segments the signal into a series of homogenous linear models. The segmentation is then used to provide statistical information about downhole measurements. Signal processing outputs have been designed to be probabilistic to account for uncertainties. The probability that pump intake pressure and pump discharge pressure will converge toward the same value is one example of such output. The probability of a noisy signal is another illustration of a result from the processing module. This real-time process is used to analyze all the ESP or PCP measurements available on specific criteria. Those pieces of information allow the expert system to predict pump failures. A Bayesian network with its probabilistic reasoning capabilities has been chosen to reproduce the ESP or the PCP physical knowledge. This Bayesian network contains input nodes gathering artificial lift parameters features and output nodes inferring failure probabilities.
During a test in real conditions, this concept showed its capability to predict and correctly diagnose the failure. In addition, this solution confirmed its robustness with accurate failure prediction under numerous operational conditions—even when downhole parameters were missing. This concept could be used to reduce reaction time to a failure, improve the monitoring capacity of each surveillance engineer, and improve the ESP life expectancy by early remediation of failure signs.
Partially Penetrating Hydraulic Fractures: Pressure Responses and Flow Dynamics
Authors: Al Rbeawi Salam , Tiab D.. 
Published: March 2013

AbstractHorizontal wells with multiple hydraulic fractures have become a common occurrence in the oil and gas industry, especially in tight formations. Published models assume that hydraulic fractures are fully penetrating the formations. However, studies have shown that fractures are not always fully penetrating the formations.This paper introduces a new technique for analyzing the pressure behavior of a horizontal well with multiple vertical and inclined partially penetrating hydraulic fractures. The hydraulic fractures in this model could be longitudinal or transverse, vertical or inclined, symmetrical or asymmetrical. The fractures are propagated in isotropic or anisotropic formations and considered having different dimensions and different spacing. This technique, based on pressure and pressure derivative concept, can be used to calculate various reservoir parameters, including directional permeability, fracture length and percentage of penetration. The study has shown that the pressure behavior of small penetration rate is similar to the horizontal wells without hydraulic fractures.A type curve matching technique has been applied using the plots of the pressure and pressure derivative curves. A set of type curves, which will be included in the paper, have been generated for the partially penetrating hydraulic fractures associated to the horizontal wells with different penetration rates. A step-by-step procedure for analyzing pressure tests using these type curves is also included in the paper for several numerical examples.
Rigorous Simulation of Production from Commingled Multilayer Reservoirs under Various Crossflow and Boundary Conditions
Authors: Villanueva-Triana Bielenis , Civan Faruk 
Published: March 2013

Abstract
An improved commingled well production model is presented by coupling of hydraulics of various reservoirs zones with wellbore in multilayer reservoirs considering different wellbore and formation cross-flow and external boundary effects, including water-influx. The pressure and production of each layer is described by the leaky-tank model of Civan (2000) under prescribed cross-flow and boundary effects. The pressure and flow along the wellbore is determined by means of the Cullender-Smith (1956) model. A Newton-Raphson iterative finite-difference numerical solution is obtained for the strongly-coupled model for accurate analysis of the optimal production, injection, and shut-in conditions at the surface for reservoir systems containing more than one layer. Application of the proposed model is demonstrated by simulating and analyzing a reservoir containing three producing layers, each having different effective thickness, permeability, skin factor, and initial reservoir pressure. The robust commingled reservoir production simulator presented in this paper may be instrumental for prediction of the prevailing fluid flow and pressure profiles along the wellbore and various reservoir layers.
More Accurate Method to Estimate the Original Gas in Place and Recoverable Gas in Overpressure Gas Reservoir
Authors: Ling Kegang , Wu Xingru , Zhang He , He Jun 
Published: March 2013

Abstract
Overpressure gas reservoirs with close-boundary typically have downward curving in p/z plot. The overestimations of original gas in place (OGIP) caused by incorrect extrapolations of early production data are often observed in reserve evaluation. To eliminate this error, a comprehensive compressibility term that includes the rock compressibility, water compressibility, and gas solubility in water has been introduced into the p/z plot.
To satisfy the above objective, it's critical to obtain the right average reservoir pressure corresponding to the drained gas reserve at the time point. But for overpressure gas reservoirs, if we completely ignore the permeability changes as the reservoir pressure declines, the reservoir performance cannot be representative. Another substantial deficiency of the conventional method is that the solution gas in connate water is also habitually neglected in estimating the OGIP. As a result, the contribution of solution gas to the total gas production is omitted in the material balance equation (MBE). These lead to the inaccurate estimation of the OGIP and gas reserve.
Considering the permeability is not constant throughout the reservoir life, but a function of pressure, rock and fluid properties, production volume, and original pore volume, a new form of MBE is presented by this study. It includes the effects of the permeability change due to pore compaction and the contribution of solution gas in connate water to the total gas production. With the proposed semi-analytical equations, the average reservoir pressure and reservoir deliverability can be estimated accurately. Therefore the evaluations of OOIP and recoverable gas are more reliable.
Tactics and Pitfalls in Production Decline Curve Analysis
Authors: Ling Kegang , Wu Xingru , Zhang He , He Jun 
Published: March 2013

Abstract
The decline curve analysis (DCA) is one of the most important methods in production forecast. It has been widely used among all the dynamics methods to estimate recoverable hydrocarbon. Decline curve can be divided into three categories: exponential decline, hyperbolic decline, and harmonic decline. Superficially decline curve analysis is the simplest prediction method, but as we dig into the base for DCA we find that it is not as simple as we think before. The opinion that DCA just follows the production trend can lead to tremendous errors, or even ridiculous results.
A good DCA requires a solid background in reservoir engineering, production engineering, and even drilling engineering. In-depth knowledge is necessary on studied reservoir, surface production facility, and the drive mechanism. In this study, several tactics developed from experience are applied to get practical and effective DCA and some pitfalls are pointed out to avoid the error or inappropriate forecast in DCA. With these tactics and pitfalls in mind, DCA can be a very useful and powerful tool in predicting recoverable hydrocarbon. Applying the established tactics and acknowledged pitfalls presented by this paper would lead to an accurate production forecast and reasonable reserves evaluation.