bluuebunny/crossref_metadata_2025_split huggingface dataset:
Polymeric Solutions to High Gas Influx in an Oil Producing Well: A Field Experience
Authors: Okeke Chinyere , Mofunlewi Samuel , Bankole Abidemi , Agbogu George U. 
Published: February 2012

Abstract
Petroleum production engineering aims to maximize oil and gas production in a cost-effective manner. Wells in one reservoir can be considered oil, condensate and gas wells, depending on the producing gas-to-oil ratio. As the wells produce, this designation can change, for example as oil is produced and gas or water reaches the perforated interval and becomes dominant in the production stream. This type of change is often undesirable and requires intervention to restore preferred productivity.
This paper describes a gas-shutoff intervention operation in an oil-producing well. The well was initially completed in September 1974, but recently the two upper sets of perforation began to produce excessive gas. The operator wanted to cease producing from those perforations and instead produce only the lower (oil-producing) perforations.
After considering various gas-shutoff options, the operator chose to use a permanent polymeric gel for the operation. The gel is formulated with low-molecular-weight polymers, which penetrate into the matrix pore spaces for a complete shutoff squeeze treatment.
This paper will describe laboratory testing, field experiences, challenges and operational procedures to create a number of conclusions about lessons learned and best practices for polymeric gels in gas shutoff operations.
Overview of Polymer Flooding (EOR) in North Africa Fields – Elements of Designing a New Polymer/Surfactant Flood Offshore (Case Study)
Authors: Shehata Ahmed M. , Ghatas Ahmed , Kamel Mahmoud , Aly Ahmed , Hassan Ahmed 
Published: February 2012

AbstractWhen petroleum reservoirs are depleted by primary recovery mechanisms only small fractions are produced (5-30%). Implementing a secondary recovery, water flooding, would still not produce all the recoverable oil present in the reservoir due to a poor sweep efficiency as the result of bypassed or upswept oil. Use of polymer flooding increases water viscosity which controls water mobility thus improving the sweep efficiency, thus increasing the recovery factor. Many successful polymer projects have increased recoveries of 3-10%.This paper presents a case study to investigate the effectiveness of polymer and surfactant flood in Offshore Egyptian Field. This field is located in the Gulf of Suez, and the reservoir is sandstone formation with active water aquifer and has very high permeability in the order of few Darcies. The reservoir contains medium quality crude having viscosity of 17.5 - 24 cp with mobility ratio of 22 – 49 which makes it a good candidate for polymer flooding especially the reservoir has high residual oil saturation.The objective of this paper is to present an extensive review of the polymer flooding literature and what constitutes a successful polymer flood project worldwide.We performed a reservoir simulation study to investigate the effect of different parameter on the polymer flooding performance using a sector model of the field. Parameters such as polymer type, polymer solution viscosity, polymer slug size, and slug concentration will be studied to come with different scenarios for evaluation and optimization of the polymer flooding pilot. This will be a key to evaluate the polymer flooding technique in the early stage of oilfield development.Results of this paper, will present the methodology needed to design a polymer and surfactant flooding project and it will provide the steps and data needed from the core lab (related to the rock qualities) and fluid lab to calibrate and have representative reservoir simulation sensitivity runs to optimize the design. This paper will focus on a case study from North Africa to implement offshore polymer flooding.
Methodology for 3-D Reservoir Modeling Leads to Retrieving the Complexity of Limited Drilled Wells and Improving Development Decision Making for a Clastic Gas Reservoir, Qawasim Formation, Onshore Nile Delta
Authors: Reda A.. , Hashem A.. , Darwish M.. , El Ghanam M.. 
Published: February 2012

Abstract
The 3-D distribution of property data is a powerful tool for understanding the spatial distribution based on hard well data and trends. The primary goals for building a 3-D reservoir model is to maximize the value of data by incorporating all available information into a quantitative, digital representation, handling large amounts of data, providing consistent analysis in 3-D, giving direct numerical input to flow simulation and pore-volume calculation, testing and visualizing multiple geological interpretations, and assessing uncertainties.
Integration is required to build a realistic 3-D reservoir geological model, including geophysics, geology, core, wireline logs and production data, and the reservoir engineering model. It imperative to minimize the uncertainties associated with volume estimations coming from a limited number of drilled wells in the field, reservoir geometry and geological structures, inconsistency of petrophysical properties, and water contact location.
In the present study, only one well is drilled in a relatively large area, leading to complications and consistent population of facies and petrophysical properties controlled by well data that assumes the homogeneity of the entire area. The uncertainties in defining original hydrocarbons in place, recoverable reserves, reservoir flow, and communications between reservoir layers become too high to optimize field performance and future development plans. Advanced modeling scenarios are performed based on the possibility of facies changes across the field area, seismic-depth conversion tolerance, field geometry, and structure. A perfect 3-D static reservoir model resulted, which matched identically to the dynamic reservoir engineering model and production history.
This paper explores a new methodology for 3-D reservoir modeling for fields with a limited number of drilled wells for the better understanding of field volumetrics and dynamic behavior and improving the decision on how, and where, to develop the field to drill more wells.
Numerical Modeling of Counter-Current Spontaneous Imbibition during Underbalanced Drilling
Authors: Naseri Masoud , Sinayuc Caglar 
Published: February 2012

Abstract
Mud solid and filtrate invasion are the most common causes of formation damage during overbalanced drilling (OBD), which is a method of drilling in which the wellbore pressure remains greater than formation pressure. During the past ten years, underbalanced drilling operations (UBD), which can be defined as a drilling method in which the wellbore pressure is less than formation pressure, has been growing due to their applications such as prevention of lost circulation, reduction of filtration lost in naturally fractured and mature reservoirs.
It is very difficult to always maintain the underbalanced conditions in drilling and completion operations during bit changing and tripping operations. In these cases due to the non-existence of internal and external mud cake, there will be high amount of mud solid and filtrate invasion into the formation.
Besides these, the potential of formation damage still exist during UBD due to Counter-current Spontaneous Imbibition (COUCSI) process. In this case, for water-based muds the original water phase pressure in the reservoir is less than the irreducible water saturation. Therefore the capillary pressure and wettability characteristics of the formation can result in water invasion from the drilling fluid into the formation.
The main goal of this study is modeling of this process for a vertical and horizontal well in a conventional reservoir, which are being derilled using a water-based mud system in an underbalanced mode, investigating the effects of some factors such as amount of underbalanced pressure difference and exposure time. In addition, the amount of invaded water and invasion distance are discussed too. The numerical modeling and resulting governing system of partial differential equations, the descretized forms and initial and boundary conditions are presented.
Based on this numerical modeling, it is shown that for high capillary pressure values, the amount of water invasion increases. Moreover, for lower underbalanced differential pressure and higher exposure times, water invasion and invasion distance increases too.
A Riveting Review of Worldwide Industrial Geological Carbon Capture and Storage Projects with the Junction of CO2 Emissions in Algeria.
Authors: Deghmoum Abdelhakim , Baddari Kamel 
Published: February 2012

AbstractThe geological sequestration of CO2 is a relatively new technology that seems to have rapidly maturated in providing an effective process of capturing CO2 from industrial pollutant emissions and storing it securely in deep geological formations. Through this technology, the anthropogenic CO2 emissions can be reduced by 20% globally by 2050. Furthermore, it is expected that by the end of this century, more than 55% of CO2 emission can be captured and stored geologically. The compression, the transport and the injection of CO2 have been well used and controlled in the petroleum industry for many decades. However, CO2 capture process remains the weak point that should be overcome in order to make CCS economically feasible at industrial level. Moreover, no risk of leakage can occur at very long term in order to make CCS technology possible and generalized.The objective of this review is to analyze and to compare briefly the quantification of CO2 emissions in Algeria and to illustrate, with different case studies, the worldwide geological CCS pilot projects, particularly, those applied at industrial scale. The review is an attempt to assess critically what has been done and to predict what is ahead in this domain.Based on this review, the authors conclude that the global warming is the consequence of human egocentrism. CO2 should be considered as a valuable gas and not a waste, and CCS as a solution to global warming. Although there is negligible CO2 emission in Algeria, In Salah CCS project, built by BP-Statoil-Sonatrach consortium, is for demonstrating that pollution has no boundaries and every country is concerned by environmental issues. Thus, developing and developed countries should be urgently implicated in a serious and strong cooperation in the deployment of CCS technology before reaching irreversible global warming consequences.
A Generalized Model for Natural Flow of Gas in a Reservoir with Power Law Trends
Authors: Kummeneje Øyvind Steinset , Jelmert Tom Aage 
Published: February 2012

Abstract
All reservoirs cannot be described by conventional models. These are characterized by constant or piecewise constant rock properties. Sometimes a power law trend may be a better assumption. Power-law trends include but are not restricted to fractal reservoirs. A concept of fractal involves the additional assumption of self-similarity.
Fracture topology, changing flow area, and heterogeneities may also contribute to power-law dependency. We use fractal nomenclature to formulate the mathematical model. The solution methodology, however, is valid for any reservoir that may be characterized by power-law expressions.
We consider boundary dominated flow of pseudo-steady type. This simplifies the partial differential to an ordinary differential equation. An approximate inflow equation pwf vs. q, may be obtained by direct integration. The natural flow rate of a well may be obtained as the intersection of the fractal reservoir inflow performance relationship, IPR, and the vertical lift equation, VLF. The proposed technique is a generalization of a classical technique to plan and design wells in homogeneous reservoirs.
Application of the proposed methodology may improve production forecasting and aid design of wells in drainage areas where the fluid follows a complex flow path towards the well. The current formulation applies to one phase flow of a real gas. The model accommodates rate dependent skin. We investigate the sensitivity of the natural flow rate to changes in reservoir and well parameters. The objective is to shed light on possible benefits of projects to accelerate and improve gas recovery. We investigate the sensitivity to skin removal, infill drilling and change of well head pressures.
Tracking Subsea Gas Wells performance without Periodic Production Testing on Test Separator
Authors: Selim I. El-S. , Shokir E. M. 
Published: February 2012

Abstract
Tracking well performance is essential in understanding reservoir behaviour, reservoir management and matching reservoir simulation models with historical data. It results in forecasting reservoir performance accurately. Also, tracking wells performance for multi-fields company with multi joint ventures is important for production allocation for fair company revenue distribution. Regular well testing is required for tracking well performance but in a subsea environment using traditional testing tools such as test separators and slick line downhole gauges to measure production rates and bottom hole pressures, would cost millions of dollars. So these types of tools don't suit a subsea environment therefor other tools to track subsea wells performance are required.
This paper presents tools to tracking subsea wells performance without test separator and by using interventionless tools such as; permanent down hole gauges, venturi and wet gas meter (WGM) with identifying uncertainty in rates measurements with these tools and focusing on measured rate validity techniques by using quality checking (QC) tools such as: a) tracking field production allocation factor b) Sensitivity on measured rates by Integrated asset model (IAM), c) using shifted well inflow performance relationship (IPR) and d)Comparing pressure drops along flow paths with initialized selected well flow correlations.
Successful applying of QC techniques on monitored rate of subsea wells for gas field Z allows for identifications of errors in rates measurements and predicting the actual well rate. These assist in simulation history matching and fair distribution to company revenues between JV partners companies.
New Methods to Predict Inflow Performance of Multiply Fractured Horizontal Wells under Two-Phase Condition and Optimize Number of Fracture Stages
Authors: Zhang He , Han Guoqing , Houeto Fabien , Lessard Rodney , Wang Wenhao , Li Jun 
Published: February 2012

Abstract
A new method is presented to calculate the total inflow and associated productivity index (PI) under two-phase conditions by a sum of contributions from matrix and N multiple fractures using semi-analytical methods. Maximizing the net Present present value (NPV), the new inflow performance relationship (IPR) models can determine the optimal fracture stage number. Furthermore, the deliverable PI is used as an input to a network model to calculate the operating rate, taking into account the network constraints such as the node pressure, allowed flowrate, or choke in place. Through this analysis, one may determine that the horizontal well of interest may not flow at the maximum PI―it suggests that the network constraints dissipate the contribution from m stage(s) fractures. The number of fracture stages is then reset to (N–m), the IPR model is rerun, and an updated PI is imported into the network model. This process is iterated until the final optimization is achieved.
This method can quickly optimize the number of fracture stages for horizontal wells under two-phase solution-gas conditions, assisting operating companies in planning field development.
A Grid-Free Method to Enhance Reservoir-Well Coupling
Authors: Li Jun , Wang Wenhao , Zhang He , Houeto Fabien 
Published: February 2012

Abstract
Reservoir and well simulations are often coupled to allow more realistic production forecasts. Proxy functions are typically generated by a well simulator as a preprocessing step to characterize the response from the production system when the reservoir condition changes. With proxy functions, a reservoir simulator can take into account the response from the well without simultaneously performing the well simulation, which can be time prohibitive. This indirect coupling is effective only when the interpolated values from the proxy function closely match the results from the surface simulation. Typical implementations of proxy functions require characterizations at each grid point, which can be expensive to compute for a fine grid. Due to the intrinsic curvilinearity of well performance curves, the accuracy of proxy functions highly depends on the number of sampling points.
In this paper, we discuss a new method for generating proxy functions that improves accuracy without sacrificing performance. We propose to use kriging to enhance the efficiency and accuracy of characterization of the surface simulation. Kriging interpolation provides a grid-free representation of the proxy function, which allows the flexibility of choosing the sampling points for well simulations. We propose to put more sampling points where the rate of change of the proxy function is relatively large.
Our numerical results show that the grid-free method reduces the interpolation error by over 40%, without increasing the number of sampling points. Furthermore, with a comparable level of accuracy, simulation time for generating the proxy function is reduced by 50%.
Effect of Presence of Crude Oil on the Performance of Emulsified Acids
Authors: Sayed M. A. , Assem A. I. , Nasr-El-Din H. A. 
Published: February 2012

Abstract
Acid treatment in carbonate reservoirs targets to restore or to stimulate the near-well area. Emulsified acid can be used in matrix acidizing and acid fracturing treatments. The delayed nature of emulsified acid is useful in creating deep wormhole and etched fracture surfaces. Almost all coreflood work done before was performed on cores fully saturated with water. Therefore, the main objective of the present work is to study the effect of presence of crude oil in the formation on the performance of emulsified acid in stimulating carbonate formation.
A coreflood study was conducted using high permeability Indiana limestone cores which have dimensions of 1.5" diameter and 6" long. The effect of the presence of crude oil inside the core on the volume of acid to achieve acid breakthrough was studied. Also, the size, numbers and distribution of the resulted wormholes as a function of the core fluid content was studied through the analysis of the CT images on the core after injection of emulsified acid. Also, the effect of the acid injection rate on these parameters was studied. Cores that are fully saturated with water and cores saturated with crude oil and water were used to study the performance of emulsified acids.
From the coreflood study, there was no optimum injection rate for an emulsified acid system when it was tested against high permeability Indiana limestone cores fully saturated with water. For high permeability Indiana limestone cores, emulsified acid enhanced the rock permeability when the acid injected at high rates. For cores saturated with crude oil and water, there was no clear relationship between volumes of emulsified acid required to achieve breakthrough and emulsified acid injection rate. Also, volumes to emulsified acid to achieve breakthrough in cores saturated with crude oil and water are greater, compared to acid volumes required to achieve breakthrough in cores fully saturated with water. Emulsified acid system is effective in stimulating limestone cores, at different acid injection rates and at high temperatures, even the cores were saturated with water or saturated with crude oil and water.
Narrow Margin Drilling and Operational Geosciences in Egypt and Syria
Authors: Tichelaar Bart W. , Salem Hisham F. , Amin Sandy A. , Shafik Ramy M. 
Published: February 2012

Abstract
The ability to drill exploration objectives safely and efficiently is controlled by knowledge of the available drilling margin. We present an application of operational geosciences for two recent exploration wells in Egypt and Syria where pore fluid pressure and fracture pressure models were built pre-drill to enable well design. While drilling the well, these models were updated in real-time (24/7) to make the right operational decisions. In addition, before drilling the more challenging well sections, learnings from shallower sections in the well were used to prepare a look-ahead assessment of the available drilling margin to select a strategy to drill the next section.
The two wells have in common that the presence of a narrow drilling margin was recognized early in the exploration phase such that proper data analysis could be completed pre-drill for the entire planned well trajectory. Furthermore, options for real-time data acquisition were investigated early such the right geoscience data could be acquired and interpreted during drilling for operational support.
Engineering, geosciences and communication form equally important components of narrow margin well execution. Real-time analysis of logging while drilling data, mud logging data and hydraulics data was used, as well as the intelligent deployment of managed pressure drilling technology, to make decisions such as adjustment of the drilling mud and selection of section depth (TD). A Communications Protocol was followed to assure that critical anomalies in the predicted drilling margin were efficiently communicated to the Drilling Supervisor for immediate operational response.
Integrated Production Analysis before Implementation Pilot Water Flooding and Surveillance & Monitoring during Pilot Water flooding on Rantau Structure Zone 600
Authors: Suarsana I Putu , Badril Areza 
Published: February 2012

Abstract
Rantau Field, located in the working area of PT. Pertamina EP, is considered as matured field. The field is located in North Sumatra, Indonesia. This field started producing in primary stage in 1930, and the secondary stage had been started in 1984 by injection of water. The water source comes from sea water with a salinity of 26000-33000 ppm. Since the injection of water quality is not good, then it had been damaged the injection wells, and it would automatically have an effect on the production wells. The oil production then started to decline.
Pertamina EP EOR management team tries to increase the oil production back by implement re-secondary recovery process. The work started from field screening, study G&G, production analysis, preparing facility production, and follow up with a pattern pilot water flooding, and finally full scale project. Pilot water flooding kick off at layer Z-600 conducted in January 2010, Pertamina EP implemented a pilot water flooding in layer Z-600 block of C1 and C2 and managed to increase oil production from two wells (0 BOPD to 400-500 BOPD) and the reservoir pressure (from 155 Psi to 222.5 Psi in 3-month period conducted a pilot water flooding). With the success of pilot water flooding on the blocks C1 and C2, Pertamina EP will continue to full scale water flooding phases are planned to be carried out gradually in block A1 and A2. In addition to conducting secondary recovery, Pertamina EP will also plan for tertiary recovery phase for blocks/compartments that have been carried out secondary recovery activities. The production analysis is very important role in injection design, the scope include production and injection performance analysis, connectivity between injector and producer, pattern design and surveillance and monitoring.