bluuebunny/crossref_metadata_2025_split huggingface dataset:
Maximizing Well Life and Optimizing Exploitation Strategies With Solid Expandable Tubulars
Authors: Contreras Jesus D. , Durst Doug , Al-Qaissy Ammar 
Published: July 2010

Abstract
Workover operations are a fact of well maintenance that can range from a simple intervention to a costly remediation. Common global issues that warrant workover operations include correcting production or injection profile issues, converting wells from producer to injectors (or vice versa), correcting cementation problems, mitigating corroded casing, fracturing or re-fracturing zones, changing artificial lift methods, and perforating or re-perforating new or existing zones.
Taking into account the wells’ lifespan is decades long, well integrity is often compromised as flow of fluid conditions cause erosion and corrosion problems. This compromise in well integrity requires a workover strategy that maximizes the well’s life cycle. Solid expandable tubular systems are a proven technology that facilitates these types of strategies. Additionally, solid expandable systems support other enabling technologies and techniques such as smart completions, multi-fracturing strategies, steam-assisted gravity drainage (SAGD) applications, and unconventional enhanced oil recovery (EOR) strategies.
This paper explains how an operator with existing wells in northwest Texas conducted a workover program converting gas producers to CO2 injections. Because the oil in place had the potential to equal that of the remaining oil in the reservoir, the optimal approach would require a solution that prevented sacrificing hole size. Solid expandable tubular systems installed in more than 25 wells isolated the existing upper perforations and enabled injection through newly-perforated lower oil intervals.
CO2 injection remains an important EOR method in the US in spite of oil price swings and ownership realignments. This is especially true in the Permian Basin of West Texas and New Mexico. Over 95% of the CO2 flooding activity is in the United States, mainly in the mature Permian Basin of the southwestern U.S., and dominated by injection under miscible conditions. (Kulkarni et al, 2008) There are 1,673 reservoirs in the onshore lower 48 United States which are candidates for CO2 miscible flooding. These reservoirs were identified using the following criteria: (Kulkarni et al, 2008)API Gravity greater than 22 degrees.The reservoir pressure greater than the minimum miscibility pressure.Depth greater than 2,500 ft.Oil viscosity less than 10 cp.Current oil saturation is greater than 20% of the pore volume.Either sandstone or carbonate rock.
This paper discusses operational procedures to explain the workover strategy and its relationship with the exploitation strategy – which was to optimize final recovery of reserves and maximize the life cycle of existing assets.
Polymer Compositions for Sand Consolidation in Oil Wells
Authors: Lahalih S. M. , Ghloum E. F. 
Published: July 2010

Abstract
Several polymer formulations were prepared and they have been characterized for their physical and chemical properties with viscosities ranging from 14 cP to 418 cP for concentrated solutions and from 3.5 cP to 15.8 cP for diluted solutions when measured at 80°C. Several polymer formulations met the critical test of stability when sand cores were immersed in 3% KCl brine stored at 80°C for over 1000 hrs. Also several formulations gave very significant improvement in the compressive strength of the treated sands that exceeded the minimum compressive strength of 10 Kg/cm2 by a factor of two to three. The safe compressive strength of oil producing well formation is reported to be about 10 kg/cm2 in order to have a stable formation that sustains shear bands. These polymeric compositions were also tested on Kuwait dune sands and actual oil well formation sand of Minagish oil well MN-117 in Kuwait. Results show that compressive strength values of three to several folds of the recommended values for oil formation were realized. Values of 35-100 kg/cm2 were achieved from this work. Improving compressive strength of weak and friable formation is one of the three main requirements for a successful sand consolidation treatment. Core flooding test on sandpacks made from dune sand and Minagish well MN-117 sand show that all polymer compositions developed compressive strengths in the treated sandpacks that far exceeded the minimum requirement of 10 Kg/cm2 and gave complete water shutoff to water production. Finally higher temperatures required higher doses of these compositions where 1.0 PV, 0.4 PV and 0.25 PV of these polymers were needed to produce the desired compressive strength at 110°C, 80°C and 60°C respectively.
Combining the Use of ESPs and Distributed Temperature Sensors to Determine Layer Water Cut, PI, and Reservoir Pressure
Authors: Camilleri L. A. , Akram A. H. , Quinzo Bravo M. E. 
Published: July 2010

AbstractIn many oil wells, production is commingled from several layers. In such environments, understanding the properties of individual layers is essential to reservoir surveillance and production optimization. The inflow properties that typically require measuring are productivity index (PI), water cut, and static reservoir pressure. These measurements have traditionally been taken with wireline-conveyed production logging tools (PLT); however, in many wells and operating environments, completion and logistic considerations make running these tools difficult or even impossible. In those instances, an alternative is required. This paper presents a new procedure based on multirate testing in combination with distributed temperature sensors (DTS), an electric submersible pump (ESP) fitted with a gauge in the commingled fluid stream, and conventional surface testing. The additional test rates provide sufficient equations to resolve all the unknowns, whereas the DTS provides essential information such as which layers are producing and which are taking fluid, as well as a mass flowrate tool for measuring the flow rate of each layer. The procedure requires varying well flow rates over a range sufficient to ensure that all layers are producing, which in many cases requires an ESP to provide sufficient drawdown to overcome crossflow as well as a variable-speed drive to establish the test rates. The theoretical basis for the protocol is described, and an example is detailed to demonstrate the validity and robustness of the method for determining inflow properties. Finally, theoretical and practical guidelines are provided to demonstrate how the test procedure is affected by fiber-optic resolution, fluid properties, and the geothermal gradient. For wells equipped with forms of artificial lift such as ESPs, beam pumps, and progressive cavity pumps (PCPs), running PLTs is often not possible because of the completion obstruction. In such cases, this new DTS-enabled procedure has the potential of becoming the PLT substitute of the future.
A New Environmentally Friendly Clay Stabilizer
Authors: El-Monier I. A. , Nasr El-Din H. A. 
Published: July 2010

Abstract
Clay stabilizers are means to prevent fines migration and clay swelling, which are caused by the contact of formation with low salinity or high pH brines. Previous clay stabilizers including: Al and Zr compounds and cationic polymers have several drawbacks. Al and Zr compounds can be removed by acids. Cationic polymers can cause formation damage in some cases, and their environmental impact is questionable. There is a need to develop new clay stabilizers that can work following acid treatment and are environmentally acceptable.
Laboratory studies were conducted on newly developed Al compound. Zeta potential and particle size measurements were used to determine surface charge of four types of clays: kaolinite, illite, montmorillonite, and chlorite; and to optimize clay stabilizer concentration. Coreflood experiments were conducted on Berea sandstone cores (1.5 in. diameter and 6.0 in. length) to assess the effectiveness of the new compound and determine the impact of acids on its performance. Atomic absorption was used to measure the concentrations of Al, Mg, Ca, and Fe in the core flood effluent.
The new clay stabilizer was very effective in mitigating fines migration. Zeta potential indicated that the isoelectric point at which complete shields of surface charge of clay particles was achieved at a stabilizer concentration of 0.2 wt%. Coreflood tests showed that this new chemical was effective, and unlike previous Al compounds, it did not dissolve in acids. In addition it is environmentally friendly compound, and also worked very well at 200°F. The behavior of the new stabilizer was much better when it was prepared in DI water than in brine.
Effectively Enhancing the Near-Wellbore Stimulation Treatment Using Fluidic Oscillation Technique
Authors: Kritsanaphak Kritsana , Tirichine Salah 
Published: July 2010

Abstract
Near-wellbore damage can cause severe reduction in effective permeability and production. A typical solution for near-wellbore damage removal involves wellbore cleanout and squeezing the treatment fluids into the formation through perforation with a conventional jetting-nozzle run on coiled tubing. However, there are numerous old wells in North Africa oil fields that have been completed with a slotted or preperforated liner and require an effective near-wellbore stimulation to remove the damage and restore the near-wellbore permeability and production.
A fluid-oscillation technique created by a fluidic-oscillator (FO) tool was applied successfully in conjunction with stimulation treatments, such as matrix acidizing, salt, and asphaltene treatment. The results from using this tool instead of the conventional jetting tool were significant. The post-stimulation production improved over previous stimulation gains when performed on the same wells. Recently, the fluid-oscillation technique was also applied effectively for near-wellbore stimulation treatments in horizontal wells without requiring matrix squeezing. Results from using this technique have been promising and have simplified the near-wellbore damage treatments. Several wells in this field were treated using this near-wellbore stimulation treatment, resulting in significant production gains. Using the matrix and near-wellbore stimulation in conjunction with the FO tool has become the preferred method to enhance the effectiveness of treatments.
The FO tool creates pressure waves within the wellbore and formation fluids that break up near-wellbore damage to restore and enhance the permeability of the near-wellbore area. As the damage is removed and the original permeability is restored, the pressure waves can penetrate deeper into the formation matrix for more complete damage removal. The direct comparative results from using conventional jetting nozzles and FO tools for several wells in a North Africa oil field are quite evident and are presented in this paper. This technique should help other operators enhance the effectiveness of near-wellbore treatments to achieve similar benefits.
An Analysis of CO2 Storage Prospects in Deep Saline Reservoirs
Authors: Huo Da , Jalali Younes 
Published: July 2010

Abstract
We analyze the prospects of CO2 storage in deep saline reservoirs. Our analysis indicates that the outlook for this method of CO2 storage is favorable. Although this is a subjective assessment, we attempt to clarify the factual trends underpinning this perspective. This includes the robust trend in growth of natural gas demand, severity of the sour gas problem, precedence in governmental action in the form of fiscal deterrents to CO2 emissions and stimulants for geological storage, and the large footprint of deep saline reservoirs.
It is therefore not surprising that the few industrial-scale projects implemented for direct storage of CO2 in geological formations all adhere to the same blueprint – sour gas fields in relative proximity of deep saline or bottom-water reservoirs, developed in countries where government is adopting a proactive approach to curbing CO2 emissions, by levying tax and by assuming the long-term liability of these projects.
Modeling of Crude Oil Asphaltenes Deposition: In-depth Colloidal Prospective
Authors: Al-Huraibi Nasser , Belhaj Hadi 
Published: July 2010

AbstractAsphaltene deposition may occur during primary or gas miscible injection recoveries, taking place almost at any stage of production from the reservoir all the way to surface facilities. Change of reservoir oil chemical composition, temperature and/or pressure during depletion leads to a state of disequilibrium that induces asphaltene precipitation causing major production problems. Asphaltenes are the polyaromatic and polar components of crude oil that are insoluble in lower molecular fractions of oil but soluble in toluene and benzene. Numerous experiments and investigations have been performed on crude oils in an attempt to understand asphaltene precipitation phenomenon that profoundly affects the economics of oil production in many reservoirs around the world. However, the problem with these experiments lies in the fact that they predominantly apply identical approaches to investigate asphaltene short-term removal and not digging enough into preventive measures.This study presents a novel approach to tackle the asphaltene deposition problem by virtue of applying a DC current on an oil sample to move the asphaltene colloids to one of the electrodes. Asphaltene colloid particles in this experiment proved to possess negative charges. Evidently, the asphaltene particles moved and deposited on the anode resulting in all the asphaltene being extracted from the oil. The use of an electric current in this experiment shows that this approach can be implemented in the reservoir by drawing all the negatively charged particles to a dumpster well as discussed below. Results from the experimental work and analyses are very encouraging for more investigation that might lead to something that sought for the longest time.
Novel Fluid Formulations to Remove Mud Filter-Cake without Affecting Rock Mineralogy
Authors: Fakhreldin Y.. 
Published: July 2010

Abstract
Removing filter-cake is essential for reducing the formation damage caused by drilling activities in various production and injection wells. These filter-cakes typically contain bio-polymers such as xanthan gum, poly-anionic cellulose, starch, along with bridging agents such as sized calcium carbonate particles. A novel chemical series was applied in laboratory tests; it perfectly degrades the filter cakes. Different performance tests showed that the filter cake was entirely removed after being treated with the novel chemical series. A direct reaction between the drilling mud and the novel compounds resulted in a complete loss of mud viscosity. Encouraged by the above data; core flood analysis were performed to test the effectiveness of the novel compounds on sandstone cores. The scenarios, which might occur in field applications, were simulated in the laboratory under controlled conditions and the responses of the core samples under these conditions were measured. Return permeability were approximately 100% after treatment with the new compounds. There was no swelling of the interstitial clay component of the formation plugs over a remarkable duration of time and wide range of temperatures.
Hydraulic Fracturing in Iran-Lessons From Four Case Histories
Authors: Heydarabadi F. Roshanai , Moghadasi J.. , Safian Gh. A. 
Published: July 2010

AbstractFrom decades ago till now, most oil wells in Iran produce using their natural flow potential and they don’t need to be fractured. This is why few cases of hydraulic fracturing are recorded in the history of Iranian oil industry. This paper reviews the three cases of acid fracturing previously conducted in an Iranian oil field based on the available data. In addition, a mere propped fracturing was also designed to be carried out but due to some problems the whole operation was cancelled. As time goes by, the reservoir pressure depletes and the need for hydraulic fracturing as stimulation practice arises. Studying the previous fracturing jobs is beneficial when designing a new treatment, thus lessons can be learnt from them.The status of the candidate selection of these wells is discussed firstly in this paper. It is important to choose appropriate wells for such an expensive stimulation practice as hydraulic fracturing. Through modeling the wells the effects of fracturing on the production performance, i.e. production rate, of these wells are considered. A successful hydraulic fracturing should improve the productivity of the well. The available build-up tests are also investigated to diagnose any induced fracture in the formation. Fracturing the formation changes the flow regime around the wellbore and this change can be distinguished through analyzing pressure transient testing data.
Hybrid AI and Conventional Empirical Model for Improved Prediction of Log-Derived Permeability of Heterogeneous Carbonate Reservoir
Authors: Weldu Tadesse , Ghedan Shawket , Al-Farisi Omar 
Published: July 2010

Abstract
Proper permeability distribution in reservoir models is very vital for reliable full field development and optimization in terms of well placement and completion strategy, managing wells’ and field’s production and injection rates in addition to estimating the recovery factor. Despite its importance, however, it is still one of the most difficult petrophysical properties to model or predict accurately.
Reliable permeability data are those derived from core measurements conditioned to well-test permeability. In most cases, however due to cost and other issues, no more than 10% of the reservoir wells are cored. To fill the gap, many approaches have been undertaken to predict permeability in the non-cored wells from log data.
Besides conventional empirical techniques, recent studies show that Artificial Intelligence (AI) technologies can predict permeability from conventional well logs with better accuracy. This study employs hybrid of both approaches to improve the prediction of permeability of a very heterogeneous carbonate reservoir.
This study was conducted in three main phases. In the initial phase, reservoir layers were grouped considering data availability and layers’ lithology, and petrophysical data. Then each group was divided into at least three clusters depending on porosity and core permeability cross-plots. In the second phase, Adaptive Neuro Fuzzy Inference System (ANFIS) has been designed to predict the index of the rock clusters based on wells’ GR, Rxo, and Porosity logs. The final phase encompassed the utilization of conventional curve fitting techniques to predict the permeability. This prediction was further improved by introducing corrections depending on the core versus predicted permeability cross-plots. Considering the heterogeneous carbonate reservoir under study, this hybrid approach proved to be superior over applying either the conventional approach or the Artificial intelligence method. Plots of depth versus core and predicted permeability shows very good match for all wells considered in this study.
Expanding the Role of Resistivity Image Logs Using Improved Acquisition and Interpretation Techniques
Authors: Kuchinski Robert , Kalathingal Paul 
Published: July 2010

AbstractThe use of the resistivity image data is becoming a more common tool in the search and development of hydrocarbon accumulations. Regardless of the resource type, play type or environment of deposition, image data is becoming more important in order to assess the potential of these reservoirs.This paper will discuss the advances in technology on the hardware side that allow for the acquisition of higher quality image data in routine and extreme borehole environments. The use of improved processing techniques will also be discussed which allows for improved reservoir characterization in a wide range of reservoirs compared to only using the conventional open hole log suite. The high resolution quality of image data compared to the basic open hole data, for example will allow for fracture visualization down to 2mm. Other petrophysical analysis using basic open hole data will average out the fine details of the fracture and its effects on porosity and permeability. Image based petrophysics known as "Image petrophysics" allows for the conversion of high resolution image data to high resolution petrophysical properties which provides greater understanding of the impact of the fractures on reservoir characterization. The use of image data calibrated with either core data or basic open hole data allows for the derivation of high resolution porosity distribution. Permeability derivation can also be achieved using image data calibrated with core data. This process can also be extrapolated to wells that are un-cored.This paper will also discuss the challenges of acquiring image data from challenging borehole environments by employing memory based image tools that can be conveyed using a broad range of conveyance techniques.
A Decision Support System for Cost-effective Assessment of Sand Production Risk and Selection of Completion Type
Authors: Rahman Khalil , Khaksar Abbas , Kayes Toby 
Published: July 2010

Abstract
Mitigation of sand production is increasingly becoming an important part of field development as the petroleum industry is expanding its production operations in more challenging unconsolidated rocks and depleted reservoirs with more complex well completion architecture. Reliable sand production assessment methods are essentially based on geomechanical approaches that integrate in-situ stresses, reservoir pressure and its depletion trend, rock strength, well trajectory, completion type and planned drawdown. Use of grossly empirical, often unreliable, methods to infer sand production risk could result in either unnecessary an upfront sand control cost or sand management cost during production due to unpredicted sanding.
This paper demonstrates by application to a field case in South East Asia how to develop and use a decision support system for credible sand production assessment and completion selection. Once a geomechanical model is built and sand production assessments have been carried out for a few wells by a robust sand production prediction model, the knowledge and information can be converted into a decision support system for new wells in the field. Provided the field Earth stresses and the reservoir pressure are applicable, the system then needs only a log-derived rock strength profile for sanding evaluation and decision making for new well trajectory and completion configuration. Using the existing geomechanical model, calibrated log-derived rock strength profiling and field supported sanding prediction, a simple flow chart is developed to assist well engineers to decide the completion type by taking into account the risks of sand production and hole collapse during production. The availability of such a decision support system assists the well and production engineers to follow a quick, cost-effective, simplified but sound approach for sand production assessment and completion selection as opposed to being grossly empirical, or too rigorous.