bluuebunny/crossref_metadata_2025_split huggingface dataset:
Simulation Study of a New CO2-WAG-Based Method to Improve Oil Recovery of an Abandoned Water-Invaded Reservoir
Authors: Taheri R. S. S. , Tavakkolian M. 
Published: July 2010

Abstract
Active aquifer is one of the most common driving forces in a producing oil reservoir. But invasion of water from the aquifer into reservoir and raising the level of WOC cause a volume of oil to be remained in water-invaded zone, which is significant in most cases.
As a research, we studied on a field case with an active aquifer which has been encroached the oil zone till abandonment condition. As a remedy, after abandonment of the reservoir, we inject a miscible gas (CO2) to recover the remaining oil. It works like a one-cycle WAG injection, in which, water injection has been done naturally by aquifer and we continue the process by gas injection.
We investigated different gas injection scenarios to inspect the effect of this method on recovery of the oil remained in water invaded reservoir. This study shows that it is possible to increase the recovery factor considerably by choosing the right gas injection scenario. The feasibility study based on economical and surface facilities considerations would help us to select the best scenario.
Enhancements To GPS-Based Subsidence Monitoring At The Wilmington Oil Field
Authors: Baghdikian S. , Jepson J. D. , Henry M. J. , Holtz K. , Bock L. , Fayman J. , Mader G. 
Published: July 2010

Abstract
Subsidence was first identified in the Wilmington Oil Field in the 1940s. The City of Long Beach, Gas and Oil Department (LBGO) has been conducting surface elevation surveying using spirit leveling and, since 2002, the Global Positioning System (GPS). Recently, software for the LBGO Deformation Network of 12 real-time GPS stations was upgraded with new state-of-the-art technologies and solutions to provide more reliable and accurate continuous monitoring to support elevation survey campaigns. Current oil field waterflood management practices as they relate to surface elevation changes and benefits from the software upgrade for Wilmington Oil Field subsidence monitoring and control are discussed.
Waterflood operations in the Wilmington Oil Field are managed for effective oil recovery and injection/production balancing while maintaining stable surface elevations for continued regional economic growth. For cost-effective and timelier surface elevation monitoring, a real-time GPS network provides control for all LBGO subsidence monitoring activities. Using mobile GPS survey equipment, quarterly and semiannual elevations of over 240 bench marks are calculated from the 12 permanent GPS stations' elevations.
The LBGO GPS network and software allow for realtime elevation monitoring of key locations and automated data processing, with the regional picture updated semiannually. Surface elevation contour maps and individual survey bench mark elevation trends as a function of time allow for timely adjustments to the waterflood operations to maintain effective oil recovery.
Real-time GPS monitoring of surface elevations provides the capability for early detection of surface deformation resulting from production/injection imbalances. The necessary operational adjustments can then be identified and implemented to mitigate the situation. The advantage of early detection is in minimizing the extent of irreversible reservoir rock compaction, resulting in more stable future surface elevations and preventing elevation changes detrimental to surface infrastructure.
Rebutting Enhanced Oil Recovery by Cyclic Water and Oil Floods
Authors: Yu Li 
Published: July 2010

Abstract
In a recent work by Loahardjo et al. (2008), it was shown that a consistent trend of increase in oil recovery can be achieved by cyclic water and oil floods into an asphaltic reservoir. However, our experimental results obtained from strict one-dimensional two-phase flow at a low constant flow rate demonstrate that it is impossible to enhance the recovery under the same experimental conditions as theirs.
We find that the oil productions before and after water breakthrough consistently decrease in the subsequent injections (floods). The consistent decrease in oil recovery in the cyclic injections is confirmed both experimentally and theoretically, and comprised as follows: Less oil recovery before the water breakthrough is caused by colloidal asphaltenes that block the throats during the preceding oil injection. Consequently, the continuous large-throat-controlled domain shrinks and the pore-throat aspect ratio reaches the critical value in greater number of pores, so that less channels for the invading front and additional disconnection of oil by snap-off occurs during the subsequent water injection.Less oil recovery after the water breakthrough is caused by destruction of the asphaltene layers deposited on the solid surfaces by the preceding water injection, so that there is even more disconnection of oil by snap-off during the subsequent water injection due to the solid surfaces that have become more water-wet.
Furthermore, experiments in this work show that the original wettability can be restored only if the water-wetted channels in a rock are soaked with asphaltic crude oil under high temperature for a long time period. Therefore, under oil-field operational condition, the wettability of the oil formation will not be restored as much as it has been in the original reservoir, unless more heat is added into the recovered reservoir.
Horizontal Well Performance Flow Simulation CFD-Application
Authors: Zeboudj F.. , Bahi L.. 
Published: July 2010

AbstractAn understanding of flow along horizontal wells can be important for reservoir management, specially: Tight and shale reservoir. As the completed length in such wells is considerably larger than that in conventional vertical wells, the flow field inside the wellbore can have a significant impact on the overall production characteristics of an oil reservoir. Flow in a well-bore is different from conventional pipe flow due to the presence of wall inflow (as in production wells) or outflow (as in injection wells), and this affects the wall friction, acceleration, and flow patterns inside the pipe. To better understand wellbore flow, Computational Fluid Dynamics (CFD) simulation has been used. A significant advantage of such simulation, besides the fact that they could potentially replace actual experiments, is that they offer a large amount of information on the turbulent velocity and pressure fields, the K-epsilon turbulent model was used to identify the entrance lenth and serve petroleum engineers to locate Pwf inside the horizontal drain for IPR calculation. One of the applications of such information is the development of new techniques in the perforation technology and fracturation of shale and tight reservoir, based upon FLUENT(a commercial CFD software) simulations.
New Insights into Wormhole Propagation in Carbonate Rocks Using Regular, Gelled and In-situ Gelled Acids
Authors: Gomaa A. M. , Nasr-El-Din H. A. 
Published: July 2010

AbstractIt is well known that the efficiency of regular acid treatments goes through a maximum at an optimum acid injection rate where it gives the maximum wormhole propagation rate (ratio between wormhole length to pore volume of acid required to breakthrough). This rate is a strong function of the acid-rock reaction: diffusion of the acid to the rock, surface reaction, and mass-transport of the reaction products. Adding a polymer and other additives to the acid may affect the wormhole propagation rate. However, literature survey didn’t highlighted in details how the wormhole propagation rate will change when polymer and crosslinker will be existing with the regular acid. Therefore, the objective of this study is to determine the wormhole propagation rate of gelled and in-situ gelled acids as a function of the injection rate. The effects of temperature, lithology, and initial permeability on the wormhole propagation rate were considered in this work.A coreflood study was conducted using calcite cores at temperature range 100 to 250 °F. Injection rate was varied from 1 to 20 cm3/min using 5 wt% HCl regular, polymer gelled, and in-situ gelled acids. Calcium, cross-linker, and acid concentrations were measured for the core effluent samples.The wormhole propagation rate of gelled acid required was higher than regular acid where gelled acid required less acid volume to breakthrough. However, the wormhole propagation rate of in-situ gelled acid required was lower than regular acid where in-situ gelled acid required a higher pore volume to breakthrough. Three regions were obtained for the wormhole propagation rate of in-situ gelled acid as a function of the injection rate: Region I, where acid injection rate is low, and in-situ gelled acid wasn’t able to breakthrough from the cores at injection rate less than 5 cm3/min. Region II, where the acid volume required to breakthrough decreased as injection rate increased in the range between 5 and 10 cm3/min. Region III, where the acid volume injected increased with the injection rate at injection rate higher than 10 cm3/min. The optimum injection rate wasn’t affected by temperature, or initial core permeability. The volume required to breakthrough decreased as the temperature was increased, and as the initial core permeability increased.
Cost Per Foot Reduction by Bit Run Optimization: A Simulation Study
Authors: Ebrahimi M. , Noveiri E. 
Published: July 2010

Abstract
Weight on bit, rotary speed, bit hydraulics and more importantly bit types, are the most important parameters affecting rate of penetration and consequently the economics of drilling. Pulling a worn bit is necessary to make the drilling operations more efficient. Cost per foot calculation is a popular criterion used to predict when to pull a bit.
Simulation is a powerful tool to enhance drilling performance and thereby reducing total drilling cost. In this paper, the first 3 thousands feet of a reservoir lithology including four bit runs are simulated so that factors affecting penetration rate are optimized and the lowest possible well cost is achieved. The effects of using other bit types, weight on bit, rotary speed and bit hydraulics are simulated in an attempt to determine the optimized parameters, which result in the lowest drilling cost.
Overall, it was found that in bit runs 2, 3 and 4, a lower cost per foot can be achieved using milled tooth bits instead of tungsten carbide types. Furthermore, it can be concluded that by increasing weight on bit and reducing rotary speed in harder rocks, more favorable results are obtained while in softer rocks it is vice versa. In addition, by lowering both mud flow rate and nozzle sizes, hydraulic horse power dissipated at the bit is increased, hence decreasing cost per foot. These optimizations would save about 17% of the original well cost, which is a considerable amount of money.
Enhanced Estimation of Reservoir Parameters Using Decline Curve Analysis
Authors: Ebrahimi M. 
Published: July 2010

Abstract
Traditional decline curve analysis is an empirical procedure used mainly to predict recoverable reserves and future production rates, based on the boundary dominated declining rate. Modern (typecurve) analysis, however, are partially (Fetkovich) or fully derived analytically, based on reservoir fluid flow equations and assuming some simplifying conditions. Such typecurves are generally used for predicting reserves and future production rates as well as reservoir parameters.
In the current study, two cases have been analyzed using traditional and modern decline curves in an attempt to estimate key reservoir parameters. In the first case, an implicit reservoir simulator has been used for generating a set of declining rates for a well operating at ideal conditions, i.e. a homogenous cylindrical reservoir with isotropic permeability producing single phase oil at a constant bottomhole pressure. The generated data ware then used as an input for a decline curve analysis software to investigate the reliability and accuracy of estimated permeability, skin, and drainage area. In the second case, the declining rate of a real oil well is analyzed in terms of the previously cited parameters by the same software. The results of both cases indicate a good agreement between the actual and estimated parameters, with the Blasingame typecurve as the most accurate decline curve analysis technique.
Gas Lift Optimization in One of Iranian South Western Oil Fields
Authors: Ebrahimi M. 
Published: July 2010

Abstract
Gas lift is an artificial lift technique used to increase oil wells flow rate. In this method, high pressure gas is injected into the well oil column to reduce its average density and make it flow to the surface. The main objective in gas lift system design is to obtain the optimum gas injection rate. Obtaining the optimum gas injection rate is important because excessive gas injection will reduce production rate and also increase the operation cost. Some other parameters are also important in a successful gas lift operation that if not chosen properly, make the operation impossible or at least uneconomical; namely gas injection pressure, well head pressure, depth of operating and unloading valves, valves spacing, etc.
Field A, located in south-western Iran, has been producing oil for more than 60 years. Through that period, the early average oil production rate of 20 MSTB/D for each well has dropped severely by a factor of 8. At present, the field produces 185 MSTB/D through 73 active oil wells. However, the high reservoir pressure drop and continuous increase of water cut and gas oil ratio through the years, have influenced some of the wells to a greater extent such that the oil does not flow or flows at a lower rate than that of scheduled.
In this paper, nodal analysis is used to compare and analyze the effects of different parameters on a sample well production.Firstly, a model is constructed and matched with the real data and thereby the best fluid and well production correlations are selected. Secondly, Sensitivity analysis tests are performed and the results are compared. Finally, the optimum parameters are chosen considering economical aspects. By applying the stated optimizations of this paper, the flow rate can be increased by 80%.
Optimization of Sand Control for Unconsolidated, Shallow, and Low-Pressure Sandstone Reservoirs: A Suriname Case Study
Authors: Haskell J. B. , Toelsie S. , Mohan A. 
Published: July 2010

Abstract
Oil and gas production from unconsolidated sand reservoirs generally requires a production sand screen and usually a gravel pack in the well bore for optimum sand control. Existing criteria such as Tiffin, Saucier and Coberly have provided guidelines for conventional gap based filtration technology. However they do not apply very well to some newer technologies of today. Some of these newer technologies include Premium (2D) screens, with fusion-bonded laminates, or MeshRite (3D) screens with angular compressed metal fibers as Stand Alone Screen (SAS) completions. These screens may use multiple layers of wire mesh and a complex shaped pore opening, which result in retention performance quite different from conventional gap-based systems. Therefore with SAS completions, compatibility with the formation sand size is critical in providing optimum performance. Consequently it might be desirable to adjust existing criteria for specific types of reservoirs, in this case unconsolidated sandstone reservoirs.
A combination of SAS lab data with SAS field performance will show that existing criteria need to be adjusted specifically for unconsolidated sandstone reservoirs. A Staatsolie case study in Suriname will be presented to demonstrate the performance of these newer technology screens for specifically unconsolidated shallow-reservoirs. Staatsolie produces heavy oil from shallow, low-pressure, unconsolidated sandstone reservoirs. Wells are mainly completed as vertical open hole gravelpack with production based on progressive cavity pumps. Additional completion methods include cased hole/openhole gravelpacked and or screenless (SAS).
In the SAS pilot, 28 wells were completed with Premium or MeshRite screens. Of these, only in 6 wells fine formation sand production was measured.
Based on available Particle Size Distribution (PSD) data of 9 wells, a comparison is made between field and lab screen performance. These results will be matched up to Tiffin's criteria [8]. Based on summaries of these screen performance, guidelines for screen type selection for various completion scenarios will be developed for unconsolidated low-pressure shallow reservoirs.
Completion types to be covered in the analysis will be open and cased SAS, as the primary focus with respect to 2D and 3D screens applications.
Evaluation of Uncertainty Associated to Analytical Water Injection Models by Assisted History Match and Probabilistic Techniques
Authors: Sandoval P. , Ordoñez A. , Gomez A. , Perez E. 
Published: July 2010

Abstract
Implementation of probabilistic methods, in the analysis of the reservoir variables allow obtaining more realistic models and identifying opportunities that generate greatest impact on the models.This finally leads to obtain better a developing plan, supported in ranked desitions. Colombian Petroleum Institute (ICP) in 2003 developed the methodology ASIA (Advanced System Analysis for Injection) wich is an adaptation of CGM technic for the analytical modeling of water injection. Within it Areal and vertical distribution of water in the reservoir is modelated by the history match of the oil water ratio behavior. This paper shows the strategy used to incorporate the risk and uncertainty analysis to the ASIA methodology in order to obtain an assisted history match and a panoramic review of the parameters behavior.
A Unified Approach for Falloff and Buildup Tests Analysis Following a Short Injection/Production Time
Authors: Fuentes-Cruz Gorgonio , Camacho-Velázquez Rodolfo , Mario Vásquez-Cruz 
Published: July 2010

Abstract
Falloff/buildup tests with short injection/production time are common because of economical and operative reasons; there exist several works addressing the transient pressure tests analysis recorded under this flow conditions; however, there is no available a methodology that allows to analyze in an integral fashion the response observed under these situations. Furthermore, the two-region radial composite model (2RRCM), which considers an abrupt change in the properties of the concentric regions, is frecuently used.
This study presents a general methodology for analyzing falloff/buildup tests, particularly with short injection/production time; this methodology consists of a simultaneous match of the shut-in pressure change, superposition and normalized impulse derivatives of the test, by using the pressure drop, first and second drawdown derivatives of the model. Furthermore, a new radial composite model with a fractal transition zone (RCMFT) is also proposed for falloff tests, which considers an intermediate region with fractal behavior between the invaded zone by the injected fluid and the non-invaded homogeneous zone. New short-, intermediate-, and long-time approximations for the pressure response are introduced.
The results obtained with the proposed methodology are promising, since there is a better control on the flow model selection and parameters determination. The methodology is general for analyzing falloff/buildup tests, but it is particularly suitable in those cases where neither the conventional semi-log nor modern methods based on first derivative, can be applied. The RCMFT is helpfully for falloff tests in low mobility reservoirs, since it honors the flow dynamics occurring when an injected fluid displaces another one with lower mobility. From the field cases presented, there is evidence of the fingering phenomenon at greater scales than those ones of laboratory experiments. Therefore, it is recommendable to incorporate these tools into the transient pressure analysis workflow.
New Technology in the Bakken Play Increases the Number of Stages in Packer/Sleeve Completions
Authors: Buffington Neil , Kellner Justin , King James G. , David Betsy , Demarchos Andronikos , Shepard Louis 
Published: July 2010

Abstract
The Bakken, one of the last giants to be discovered in North America, extends from Montana through North Dakota and into Saskatchewan and Manitoba provinces in Canada. The USGS, in its latest study published in April 2008 (USGS 2008), estimates that the undiscovered US portion of the Bakken Formation holds 3.65 billion barrels of oil, 1.85 trillion cubic ft of associated gas and 148 million barrels of natural gas liquids. Being classified as an oil play dependent on full well-cycle margin efficiencies to increase profitability, technology will be a main driver in the success of the development of the Bakken.
Two technologies that have been critical to the current success of the Bakken are: horizontal drilling and hydraulic fracturing. Operators typically drill on 640 or 1280 acre spacing. Typical 1280-spaced lateral lengths are over 9,000 ft, at a total vertical depth (TVD) of 9,000 ft (Miller et al., 2008). Once extended reach horizontal drilling was proven reliable, attention was turned to optimizing production from these laterals. This paper will present an enhancement to an existing technology that enabled the operator to vastly increase the effective flow area created by staged hydraulic fracturing. In the process of bringing this technology to market, both the service company and the operator agreed that the true value-adding function was the process that enabled an expediting of the product from concept to implementation.
The development of new technology by service companies is critical for operators to expand their operations, drive operational efficiency, and work profitably in ever harsher environments that are lower on the resource triangle (Fig. 1) (Masters and Grey 1979). Product development is sometimes performed by service companies with requirements gathered from several operators, while at other times service companies will develop products specifically to meet the needs of a single operator. This paper will describe a synthesis of these processes, and the design and testing hurdles encountered, for a project that met the needs of both a single operator and the service company. The product is expected to provide continued benefit throughout the Bakken drilling and completion campaign for this operator, as well as provide a solution for the broader market for the service company. As a result of this collaborative effort, a new product was conceptualized, developed, lab tested, field tested, and taken to market in an accelerated time frame.
Fig. 1 Resource Triangle.
Adding Value to Gas Lift Evaluation With Minilogger Tools
Authors: Friedli J. , Rivas C. 
Published: July 2010

Abstract
Recent market entry of compact, integrated, "minilogger" type tools has created opportunities for improving the quality and quantity of data acquired in conventional BHPT surveys, with significant added value for gas lifted flowing surveys. These memory tools typically comprise a pressure gauge plus a high resolution borehole temperature probe and CCL. The total package is about the same size as a traditional tandem BHP gauge assembly, and may include a small spinner. When running a minilogger in place of BHP gauges, there have been predictable as well as unexpected benefits realized.