bluuebunny/crossref_metadata_2025_split huggingface dataset:
Wellbore Section Contribution in Fractured Horizontal Openhole Wells
Authors: Zhou Desheng , Li Xianwen , Zhang Kuangsheng , Yang Lijun , Mu Lijun , Li Honying 
Published: June 2012

Abstract
More and more horizontal wells are completed as openhole and fractured with multistage fractures. The question is what is the contribution of the openhole section to total production in a fractured horizontal openhole well? Based on actual production data of a horizontal well before and after multistage fracturing, the paper analyzes popular horizontal and fractured horizontal well correlations, and presents a new inflow performance model including the productions from the horizontal openhole section and fractures of horizontal wells.
The paper can be used to study the inflow performance of a horizontal gas well, and to check the contribution of a horizontal openhole section in a fractured well. The presented analyses can also be used to determine fracture numbers and whether to use openhole or cemented casing completion.
The paper presents that, for a pseudo steady state flow, the gas flow rate from the openhole can be calculated by Babu & Odeh correlation. For the flow from one fracture, the non-fully penetrating part of Guo and Evans correction gives around half of a reasonable rate, and it can be used by multiplying a factor 2.
The combination form the wellbore production and fracture production is not simply allocated by area percentages of wellbore wall and fracture surfaces. A correcting factor may be used to combine the flow rates from horizontal wellbore and fractures.
Evaluation of Multi-stage Fracturing by Hydrajet, Swellable Packer, and Compressive Packer Techniques in Horizontal Openhole Wells
Authors: Mu Lijun , Ma Xu , Zhang Yanming , Ling Yun , Gu Yonghon , Zhou Desheng 
Published: June 2012

Abstract
Horizontal openhole wells are commonly fractured by one of the three hydraulic fracturing techniques of hydrajet, swellable parker and compressive packer techniques. The paper reviews the application of 23 wells fractured by hydrajet (12 wells), swellable parker (4 wells) and compressive packer (7 wells) in tight gas sands in China. None method is overwhelming in the view of increasing production rate from the paper.
The paper presented that different treatment pressures among stages may not a signal of perfect isolation. Created traverse fracture by hydraulic stimulation may not be at the middle of two packers or at the place of opened sleeve port for swellable packer and mechanical packer stimulation. Hydrajetting is a good choice to stimulate a specific place along the entire wellbore. Unlike in vertical wells, hydrajetting may not reduce the breakdown pressure in horizontal well treatment.
The presented comprehensive comparison and discussion of the three fracturing methods will help operators understand the three methods better and accomplish production goals.
Asphaltene Deposition Study and its Effects on Permeability Reduction - A Case Study
Authors: Kharrat R. , Zargar Z. , Razavi S. M. 
Published: June 2012

Abstract
Asphaltene deposition affects the porosity and permeability which in turn reduces the production and raises the processing costs. Therefore, it is necessary to investigate more about the asphaltene precipitation and determining the amount of solid deposition causing the porosity and permeability reduction.
In this paper, it has been tried to overcome this need by simulating the process in one of the South-West Iranian reservoirs in which asphaltene problem has been encountered frequently. The wells under production were facing severe asphaltene choking problem and coiled tubing acid wash were done every six month to remove the deposited asphaltene. Flow assurance results for the fluid are clearly saying that oil is highly asphaltic although it is a light oil. In the other hand, wells under production always are required to keep the rate as long as possible due to economic limits and it was critical for the management to know the effect of asphaltene deposition in the reservoir formation on the flow rate and vice versa. The best way to see the effect is reservoir simulation in which asphaltene deposition is modeled.
First of all, the fluid model and asphaltene precipitation curve were prepared. Then, the reservoir static and dynamic models were generated based on the rock and fluid properties. The behavior of asphaltene during the production as precipitated, flocculated and deposited asphaltene were modeled using commercial software. In addition, the variation of permeability due to asphaltene deposition was obtained.
Asphaltene and permeability map were generated for the entire reservoir. Most of the deposition was found to form around and nearby the production wells. Minor permeability reduction was observed throughout the reservoir; however, major damage was around the wellbore. Both precipitation and deposition amounts were visible and can be reported and this ability increases the capability to decide better about the optimum production.
The Influence of Capillary Pressure on Phase Equilibrium of Mixed CO2-Water Injection into Geothermal Reservoirs Including Phase Appearance and Disappearance
Authors: Salimi Hamidreza , Wolf Karl-Heinz , Bruining Johannes 
Published: June 2012

Abstract
We quantify the capillary pressure effect on the phase equilibrium of the CO2-water system. Our interest is in the capillarypressure range between 0 and 100 bars for temperatures between 293 and 372 K and bulk (wetting-phase) pressures between 25 and 255 bars. For this purpose, we have implemented the capillary pressure effect in the PRSV equation of state. Inclusion of capillary pressure in the phase equilibrium of the CO2-water system makes it possible to determine the capillary-pressure effect on the CO2 storage capacity and heat-energy recovery for CO2-water injection into geothermal reservoirs. We illustrate the process using a 2D model of the geothermal reservoir in the Delft Sandstone Member, below the city of Delft (The Netherlands). The process involves phase transitions between single-phase and two-phase regions. To deal with phase appearance and disappearance, we have applied a new and effective solution approach, the so-called nonisothermal negative saturation?? (NegSat) solution approach.
The results show that the capillary pressure promotes evaporation. In the pressure and temperature range of our interest, capillary pressure reduces the CO2 solubility in water and the aqueous-phase density up to 64% and 1.3%, respectively, whereas it increases the water solubility in the CO2-rich phase and the CO2-rich-phase density up to 3,945% (40.5 times) and 1,544%, respectively. Capillary pressure shifts the CO2 liquid-vapor transition and consequently the upper critical point of the CO2-water system to a lower pressure. The intensity of the shift depends on the value of the capillary pressure and the bulk (wetting-phase) pressure. For instance, the CO2 liquid-vapor transition at T = 293 K occurs approximately at 60 bars for Pc = 0 bars, whereas it occurs at 15 bars for Pc = 45 bars.
For mixed CO2-water injection into the geothermal reservoir (200 bars &lt; P &lt; 260 bars, 290 K &lt; T &lt; 360 K), inclusion of the capillary pressure effect in the phase-equilibrium behavior does not significantly alter the capillary CO2-trapping mechanism. In other words, CO2 banks are mainly formed in the highly permeable zones that are surrounded by less permeable zones. However, for injected CO2 concentrations close to the bubble point, the effect of capillary pressure on the phase equilibrium reduces the heat recovery by 37% and the CO2-storage capacity also by 37%. For overall injected CO2 mole fractions between 4% and 13%, the reduction in the heat recovery and CO2-storage capacity is 10%. Based on simulations, we construct a plot of the recuperated heat energy versus the maximally stored CO2 for a variety of conditions; we compare the results including and excluding the effect of capillary pressure in the phase-equilibrium calculations.
Investigation of the Applicability of Thermal Well Test Analysis in Steam Injection Wells for Athabasca Heavy Oil
Authors: Ghahfarokhi Ashkan Jahanbani , Jelmert Tom Aage , Kleppe Jon , Ashrafi Mohammad , Souraki Yaser , Torsaeter Ole 
Published: June 2012

Abstract
Thermal well testing of steam injection wells offers an inexpensive quick method to estimate flow capacity and swept volume in thermal recovery processes. Pressure falloff tests are commonly used for this purpose. Estimation of steam zone properties and swept volume from falloff test data in this study is based on the theory assuming a composite reservoir with two regions of highly contrasting fluid mobilities and the interface as an impermeable boundary. Consequently, the swept zone acts as a bounded reservoir for a short duration, during which the pressure response is characterized by pseudo steady state behavior.
The purpose of this study is to evaluate the applicability and accuracy of thermal well test analysis method and effects of different parameters on results. Pressure falloff testing is simulated using a numerical thermal simulator. The generated pressure falloff data are then analyzed to calculate swept volume and reservoir parameters. Different gridblock models are considered.
Viscosity of Athabasca heavy crude sample was measured in the lab using a rotational viscometer up to 300°C. Bitumen sample molar mass was measured by cryoscopy. Density at standard conditions was measured by a density measuring cell. These data were used as input for numerical simulation purposes.
Results of this work show that the swept volume, swept zone permeability and skin factor can reasonably be estimated from pressure falloff tests. The effects of gravity, dip, permeability anisotropy and irregular shapes of swept zones are studied. It can be seen that these factors do not greatly affect the estimated results. Results of 3D models show that the estimation of permeability and steam swept volume depends on the vertical positions where pressure data are measured. It is also found that real gas analysis does not substantially improve the calculation accuracy and the pressure analysis technique suffices for all practical purposes.
Removal Efficiency of Water-Based Drill-In Fluid Filter Cake Using Polylactic Acid
Authors: Elkatatny S. M. , Nasr-El-Din H. A. 
Published: June 2012

Abstract
Water-based drilling fluids consisting of xanthan gum, starch, sized calcium carbonate and salt particles have been used to drill horizontal wells. Available chemical methods of removing filter cake like mineral acids, esters, oxidizers, and chelating agents are limited at certain conditions.
Drilling fluid was designed based on calcium carbonate particles and an ester of lactic acid. The objective of the latter is to remove calcium carbonate once the drilling operation is complete and there is a need to remove the filter cake. Extensive lab work was done to: 1) determine thermal stability of the drilling fluid (70-72 pcf) for 24 hrs, 2) characterize the filter cake using computer tomography, 3) assess potential formation damage for different rock types (limestone and sandstone) using a modified HPHT filter press, and 4) determine the removal efficiency of the filter cake and the return permeability.
The results obtained showed that the drill-in fluid has stable rheological properties up to 250°F over 24 hrs. A CT scan showed that the filter cake contained two layers, one layer close to the rock surface, which contained a mixture of calcium carbonate and acid-precursor, and one layer close to the drilling fluid that contained a mixture of XC-polymer and starch. The polymer layer was removed by using 10% solution of alpha amylase. The rest of the filter cake was removed by lactic acid that was produced from the hydrolysis of the ester. The removal efficiency of the filter cake was nearly 100% and the return permeability was about 100%, when using a ratio of polylactic acid to calcium carbonate 3 to 1. The decrease in the CT number of the core after the removal process indicated that the filter cake was completely removed and no formation damage occurred. This paper will discuss the development of this new drilling fluid and will give recommendations for field applications.
Static and Dynamic Assessment of DFN Permeability Upscaling
Authors: Ahmed Elfeel M. , Geiger S. 
Published: June 2012

Abstract
Nearly half of the remaining petroleum reserves are contained in naturally fractured reservoirs (NFR). An accurate estimate of the effective fracture permeability tensor is a key to the successful prediction of oil recovery from NFR. Standard workflows nowadays employ discrete fracture network (DFN) modeling and analytical or flow-based methods to upscale fracture permeabilities. However, DFN modeling imposes some important challenges, which can cause great uncertainty in the effective permeability tensor and subsequent recovery prediction: Analytical upscaling methods, which are commonly used due to computational efficiency, are inaccurate for poorly connected fracture networks. Flow-based upscaling methods depend on boundary conditions and are computationally expensive. Defining the optimum grid size for either method is also very difficult. In addition, DFN upscaling is often driven by practical issues such as time constrains and computational limitations, leaving little room to investigate the effects of upscaling methods and grid size.
In this paper we utilize features in leading DFN simulators employed in standard industry workflows for computing effective permeability tensors with flow-based and analytical methods. We use two realistic dataset from fractured formations of onshore reservoirs in our assessment. Not surprisingly, there is up to three orders of magnitude variation in the effective permeability based on the chosen upscaling method and perceived optimum grid cell size. This has tremendous impact on predicted recovery rates and ultimate recovery; ultimately uncertainty in upscaling can mask uncertainty in the geological model. We hence introduce a new simulation technique, Discrete Fracture and Matrix (DFM) modeling, which accounts accurately for flow in the fractures and rock matrix as an efficient alternative for computing effective permeability tensors as it allows us to assess the accuracy of classical DFN upscaling approaches, which all help reducing uncertainty in recovery prediction.
Application of Injection Fall-Off Analysis in Polymer flooding
Authors: van den Hoek P. J. , Mahani H. , Sorop T. G. , Brooks A. D. , Zwaan M. , Sen S. , Shuaili K. , Saadi F. 
Published: June 2012

Abstract
Polymers exhibit non-Newtonian rheological behavior, such as in-situ shear-thinning and shear-thickening effects. This has a significant impact on pressure decline signature as exhibited during Pressure Fall-Off (PFO) tests. Therefore, applying a different PFO interpretation method, compared to conventional approaches for Newtonian fluids is required.
This paper presents a simple and practical methodology to infer the in-situ polymer rheology from PFO tests performed during polymer injection. This is based on a combination of numerical flow simulations and analytical pressure transient calculations, resulting in generic type curves that are used to compute consistency index and flow behavior index, in addition to the usual reservoir parameters (kh, faulting, etc.) and parameters relating to (possible) induced fracturing during injection (fracture length and height). The tools and workflows are illustrated by a number of field examples of polymer PFO, which will also demonstrate how the polymer bank can be located from the data.
Overdisplacing Propped Fracture Treatments—Good Practice or Asking for Trouble?
Authors: van Gijtenbeek Klaas , Shaoul Josef , de Pater Hans 
Published: June 2012

Abstract
One of the major issues with the development of unconventional ultratight shale-gas reservoirs is related to concerns about underdisplacing or overdisplacing hydraulic proppant-fracture treatments in multiple-zone completions in horizontal wells.
In recent years, a very large number of multistage propped-fracture treatments in horizontal wells in ultratight shale-gas reservoirs have been overdisplaced to obtain a clean wellbore and avoid problems with the hardware (especially pump-down plugs) used for rapid multizone completions. Because cleanout treatments can usually be avoided by these overdisplacements, multiple treatment stages can be performed more quickly, which saves time and minimizes other added costs. However, this practice might result in poor communication between the propped fractures placed in the reservoir and the wellbore.
In some situations, such as when the rock strength is sufficient to prevent closure of nonpropped fracture areas, overdisplacing a treatment could result in a very high conductivity region at the wellbore. There is certainly a limit to the length of an unpropped fracture that could stay open for a significant time. This mechanism is similar to what has been seen in some wells with proppant production, where well productivity has increased following proppant production. Proppant production might create some open channels in the proppant pack near the perforations that remain open.
This paper discusses current overdisplacement practices and tries to address if and when overdisplacing fractures in shale- or tight-gas reservoirs could have a net positive or a negative effect on production.
Transient Gas Flow in Unconventional Gas Reservoirs
Authors: Wu Yu-Shu , Wang Cong , Li Jianfang , Fakcharoenphol Perapon 
Published: June 2012

Abstract
Unconventional gas resources from low-permeability formation, i.e., tight and shale gas, are currently received great attention because of their potential to supply the world with sufficient energy for decades to come. In the past few years, as a result of industry-wide R&amp;D effort, progresses are being made towards commercial development of gas and oil from such unconventional resources. However, studies, understandings, and effective technologies needed for development of unconventional reservoirs are far behind the industry needs, and gas recovery from those unconventional resources remains low (estimated at 10-30% of GIP).
Gas flow in low-permeability unconventional reservoirs is highly nonlinear, coupled by many co-existing processes, e.g., non-Darcy flow and rock-fluid interaction within tiny pores or micro-fractures. Quantitative characterization of unconventional reservoirs has been a significant scientific challenge currently. Because of complicated flow behavior, strong interaction between fluid and rock, the traditional Darcy law may not be applicable for describing flow phenomena in general. In this paper, we will discuss a general mathematical model of gas flow through unconventional porous media and use both numerical and analytical approaches to analyze gas flow in unconventional reservoirs. In particular, we will present analytical and numerical solutions of incorporating Klinkenberg effect, non-Darcy flow with threshold pressure gradient, and flow behavior in pressure sensitive media. We will discuss the numerical implementation of the mathematical model and show applications of the mathematical model and solutions in analyzing transient gas flow in conventional reservoirs.
Proper Design Criteria of Microemulsion Treatment Fluids for Enhancing Well Production
Authors: Quintero Lirio , Jones Thomas A , Pietrangeli Gianna A. 
Published: June 2012

Abstract
When newly drilled oil and gas wells fail to reach the expected production levels, near-wellbore damage may have resulted from fluid incompatibility, poor fluid/rock interaction and/or mechanical damage. These problems may also occur during remediation or stimulation operations, if the treatment fluid is not properly designed. The principal formation damage mechanisms that lead to these problems are in-situ emulsions, wettability changes, water blocks and scale formation. It is recognized that such reservoir damage can be removed or prevented using microemulsion technology that leads to more productive oil and gas wells.
The challenge is to design and select an optimized microemulsion system based on the reservoir conditions, such as the bottomhole temperature and the individual compositions of the crude oil, formation water, and the drilling and completion fluids. A well-designed treatment fluid should provide ultra-low interfacial tension, high oil solubilization and total compatibility with all fluids it encounters. The selection of the optimum formulation for a specific application requires a systematic study of the phase behavior of brine-surfactant-oil systems as a function of temperature and its final composition, including the salt, surfactants, co-surfactants and an optional acid.
This paper provides a comprehensive discussion of the phase behavior obtained with the brine/surfactant/oil systems used in microemulsion formulations for formation damage prevention and removal. Laboratory tests results and field applications in openhole and cased-hole completed wells have proven that the microemulsion treatment fluids are successful in the field, if there is a systematic analysis of phase behavior that identifies and defines the treatment fluid phase boundaries.
Decision Making Under Uncertainty in EOR: Applying the Least Squares MonteCarlo Method in Chemical EOR Implementation
Authors: Alkhatib A. , Babaei M. , King P. R. 
Published: June 2012

Abstract
This study introduces a decision making evaluation method for flexibility in chemical EOR. The method aims to capture the effects of dynamic uncertainties both technical and economic and produce a near-optimal policy with respect to these uncertainties as they vary with time. The evaluation method used was the Least-Squares MonteCarlo(LSM) method which is best suited for evaluating flexibility in project implementation. The decision analysed was that of finding the best time to initiate surfactant flooding during the life time of a field under uncertainty. The study was conducted on two reservoir models: 3-D homogeneous model and a 2-D heterogeneous model. The technical uncertainties considered were the residual oil saturation to the surfactant flood, surfactant adsorption and reservoir heterogeneity while the main economic uncertain parameters considered were oil price, surfactant cost and water injection and production costs. The results show that the LSM method provides a decision making tool that was able to capture the value of flexibility in surfactant flooding implementation. The LSM method provides great insight into the effect of uncertainty on decision making which can help mitigate adverse circumstances should they arise. The results found that the optimal policy obtained was reliable and that heterogeneity does affect the optimal policy. It was also possible to consider the value of information using this method.