bluuebunny/crossref_metadata_2025_split huggingface dataset:
Using Microemulsion Technology to Remove Oil-based Mud in Wellbore Displacement and Remediation Applications
Authors: Brege Jonathan , El Sherbeny Wael , Quintero Lirio , Jones Tom 
Published: February 2012

Abstract
Formation damage is a by-product of the drilling, completion, and production process and can be attributed to many factors. In openhole (OH) and cased-hole (CH) wells, hydrocarbon flow may be impeded by various damaging mechanisms caused by drilling and completion fluids, in-situ emulsions, water block, organic deposition, and oily debris left downhole.
Microemulsion fluids have been successfully developed to effectively resolve the persistent problem of near-wellbore damage. The physical-chemical properties of these microemulsion systems include high oil solubilization, high diffusion coefficients through porous media, and the reduction of interfacial tension between organic and aqueous phases to near zero, making them excellent candidates for removing formation damage. The chemistry of microemulsion fluids make these systems excellent choices for superior synthetic or oil-based mud (S/OBM) displacements in casing and for OBM filter cake cleanup in openhole completion applications. Formulations have also been developed for casedhole perforation applications as well as post-perforation remediation treatments to remove the formation damage around the perforation or fracture zones.
This paper presents a technical overview of microemulsion technology and a review of the test protocol used to qualify treatment solution designs for S/OBM displacement/cleanup and removal of formation damage in openhole and casedhole wells. Challenges and results from numerous field applications are presented that demonstrate the efficiency of microemulsion fluids for removing S/OBM debris and filter cakes, reducing near-wellbore damage and improving well productivity.
Progressing Cavity Pump Challenges in Issaran Heavy Oil Fracture Carbonate Reservoir: Case Study Issaran Field, Eastern Desert, Egypt
Authors: Shehata Alaa , Nabil Emad , El Rahman Wael Abd , Akl Hesham , Kamal Salah 
Published: February 2012

Abstract
The Issaran Field, a heavy oil reservoir with an estimated OOIP (original oil in place) of approximately 1.6 billion bbls of oil, was discovered in 1981. The producing horizons are the carbonate formations of Miocene age occurring from depths of 1000ft to 2000 ft. The oil is of 10-12 degree API with viscosity of 4000 cps at standard conditions, The original reservoir temperature is around 120 °F.
It was not until early 2000, after the crude oil prices rose to favorable levels, that a concerted effort was made at developing this heavy oil. "Cold production" from the fractured carbonate Nukhul reservoir (depth ∼2000ft) was first targeted and the production from the field increased from 170 BOPD in 1998 to over 2000 BOPD in early 2004.
Each reservoir has its own characteristic, which requires special approach to overcome its problems and optimize its production and increasing recoverable reserves. As Zeit Formation contain variable sand, Upper and Lower dolomite due to its shallow depth, the oil could not be produced as cold production, Gahrandal formation is consisted of three limestone bodies with permeability below 20 md and the last one is Nukhul zone which give some cold oil production due to its naturally heavy fracture. Theses difference characterization lead to apply different ways of reservoir management and artificial left methods for each zone(5).
These different reservoir characteristics led to the application of different types of reservoir management for each zone. The Nukhul formation wells have been completed as openhole, Gharandal formation wells have been completed as cased hole and Upper and Lower Dolomite formation wells have been completed as cased /open hole steam injection wells, producing by cyclic steam stimulation.
About 50 wells producing using PCP which represent approximately 20 % from Issaran field artificial lift system, This paper describes the progressive cavity pump performance, factors affecting pumping parameters, failure analysis and recommended action to maximize pump run life and increase well productivity
Laboratory Optimization of an Emulsified Acid Blend for Stimulation of High-Temperature Carbonate Reservoirs
Authors: Sabhapondit Anupom , Guillen Jose R. , Prakash Chetan 
Published: February 2012

Abstract
Emulsified hydrochloric (HCl) acid has been used in both fracture and matrix acidizing of carbonate reservoirs to help penetrate deeper into the reservoir before spending. The emulsion stability and adequate corrosion inhibition are critical requirements of this blend, which are challenging to accomplish using emulsified acids of high HCl acid concentration (&gt;26%) at high temperatures (&gt;250°F) because many corrosion inhibitors used in the industry can severely affect emulsion stability by interacting with the emulsifier. The requirement of other additives, such as iron-control additives, surfactants other than the emulsifier, H2S scavengers, etc., can further add to the challenges.
This work presents the laboratory optimization of 26% emulsified HCl-acid blends for use at temperature ranges between 250 and 300°F. Quaternary ammonium salt based Inhibitor I-C and a propargyl alcohol based Inhibitor I-N were used in this study. One inorganic halide based (IN-H) and one organic acid based (IN-O) intensifier were used to achieve adequate corrosion inhibition. A single commercial blend of surfactants was used for all the tests.
Based on the high-pressure high-temperature (HPHT) static corrosion tests, Inhibitor I-C performed better than Inhibitor I-N at 275°F. However, Inhibitor I-C was found more damaging to emulsion stability than Inhibitor I-N. At 250°F, the performances of both inhibitors were comparable.
A common misconception that prevails in the industry is that a stable emulsified acid can ensure a successful acid job without (or with a very little amount of) corrosion inhibitor. It was clearly evidenced during this study that the emulsion stability alone does not ensure the protection of alloys from corrosion. Using a suitable corrosion inhibitor in appropriate concentration is as equally important as emulsion stability for successful completion of an emulsified acid job without encountering severe corrosion problems.
Changing Separator Conditions During Black-Oil and Modified Black-Oil Simulation Runs
Authors: Ibrahim Mohamed , El-Banbi Ahmed H. , El-Tayeb Sayed , Sayyouh Mohamed H. 
Published: February 2012

Abstract
Several authors have shown the applicability of modified black oil (MBO) approach for modeling gas condensate and volatile oil reservoirs. MBO approach could adequately replace compositional simulation in many applications (including water influx or water injection applications). Changing separator conditions during the history of the simulation run still needs compositional simulation, since PVT properties are calculated for specific separator conditions in black-oil and MBO approaches. Some commercial simulators have treated changes in separator conditions for black-oil applications. However, and to the best of our knowledge, no such treatment exists for the MBO approach. In field operations of volatile oils and gas condensates, however, separator conditions often change because these volatile fluids are usually separated through three and more separation stages, when wellhead pressure allows. We often see that the well stream is usually rerouted to lower pressure separators at later stage of the field life.
In this work, we derived two new equations that can be easily programmed into existing simulators and will allow accurate calculations of oil (or condensate) and gas rates when separator conditions change. These equations extend the use of MBO approach and provide an alternative to compositional simulation when field operations undergo changing separator conditions. The inputs to our equations can be easily obtained from the EOS model used to generate the PVT tables for MBO simulation runs.
To validate our work, we generated many MBO PVT tables using Whitson and Torp method for a variety of fluids covering wide range of gas condensates and volatile oils. We applied our new equations to calculate oil and gas rates when separator conditions change for all these fluids. For validation of our approach, we then used fully compositional simulation and applied the same changing separator conditions and compared the rates, which compared very well. In the paper, we also show several field examples exhibiting large gas-oil ratio (GOR) and condensate-gas ratio (CGR) variations when separator conditions change, and the applicability of our technique on field data.
A Modelling Study of Severe Slugging in Wellbore
Authors: Malekzadeh R.. , Mudde R. F. 
Published: February 2012

Abstract
Developments in extended reach drilling and completion technologies allow to economically access a number of scattered small hydrocarbon pockets and will open up further opportunities for maximizing recovery from these fields. Effective use of these developments requires us to better understand the transient multiphase flow behaviour.
Undulation is associated to horizontal wells with some degrees of deviation from the horizontal. The inclination angle could be a result of a lack of sufficient drilling control or could be designed on purpose, for instance, fish-hook wells, snake wells and undulating wells. A complicated and undulating trajectory may initiate severe slugging at the bottom of a wellbore. In this paper, OLGA, a commercial transient two-fluid multiphase flow simulator, and Cheng's inflow performance relationship were coupled together to characterize severe slugging. Simulation shows that severe slugging is formed at the bottom of the wellbore and moved up to the surface. Furthermore, it creates pressure pulsation at the bottom of the wellbore that can influence the reservoir performance.
EOR vs. Infill Well Drilling: Sensitivity to Operational and Economic Parameters.
Authors: Alusta Gamal , Mackay Eric , Fennema Julian , Armih Khari , Collins Ian 
Published: February 2012

Abstract
In a previous publication we introduced a methodology to assist in choosing between Enhanced Oil recovery (EOR) and infill well drilling (SPE 143300). Operating companies are often reluctant to use EOR techniques when they have the option of infill well drilling instead. Reasons for this include how operating companies assess and manage risk and uncertainties. The methodology developed includes performing reservoir calculations to evaluate additional recovery using both techniques, and then using data generated as input to economic analysis. In the previous work, polymer flooding for 10 years after two years of waterflooding was studied using a synthetic reservoir model. The technique involved running a range of reservoir simulation scenarios to test possible recovery outcomes; these outcomes then provide input data that will be used in the probabilistic economic evaluation tool to be introduced as a follow up in this paper.
This current paper presents the results of the impact of operational factors, such as delaying the start of polymer flooding. This involves assessing the best possible timing for polymer injection to achieve optimal economics. This type of assessment is possible because the economic model developed and presented here allows input from multiple reservoir simulation sensitivity calculations. Monte Carlo Simulation (MCS) is then performed to establish confidence in the method, and test economic uncertainties and the risks associated with implementation of polymer flooding. Defining variables with a probability distribution can establish more precisely the economic value of the polymer flooding project. The analysis of uncertainty involves measuring the degree to which input contributes to uncertainty in the output.
MCS is a statistics based analysis tool that yields probability impact on Net Present Value (NPV) of the key operational parameters included in the project (oil, water and polymer production and injection costs, polymer concentration, timing, etc.) and various economic factors (oil price, polymer cost, etc).
Determining Unswept Oil in Flank Areas of Burgan Field to Successfully Place Infill Wells
Authors: Desai Sameer F. , Bora Mir Alam , Al-Matar Dawood , Rane Nitin , Al-Motairy Salem N. , Saleh Batoul M. , Al-Naser Mariam H. 
Published: February 2012

Abstract
Greater Burgan Field accounts for most of the oil produced in Kuwait. Discovered in 1938, commercial production from this giant field commenced in 1946 accelerating rapidly to a peak of nearly 3 MMBOPD in 1972. The Burgan structure is an anticlinal dome with numerous faults. The main producing reservoirs are sandstones of Cretaceous age. Four major sandstone horizons within the gross productive section account for most of the current and cumulative production. The 3SM is the main contributory sand which is much thicker than the others. A strong natural water drive maintains reservoir pressure.
The compartmentalization of the main reservoir sands by faults, combined with high production rates, resulted in water incursion problems since the early seventies and made worse by uncontrolled flow from wells sabotaged during the Iraqi invasion. As the 3SM reservoir gets further depleted, water encroachment studies reveal that there is a differential rate of rise in OWC in the massive sand implying un-even sweep. This has created uncertainties in the remaining oil column in flank areas of the field for placement of infill well locations.
This paper presents a methodology applied to successfully identify infill well locations in flank areas of Burgan field. The behavior of faults and rise in water in different compartments were analyzed utilizing seismic surveys, pressure buildup tests and PNC log data combining with production history. Based on the analysis minor faults were characterized and mapped which led to identification of unswept areas where new well locations were proposed. Gross pay found in three new infill wells drilled have been very encouraging.
The process leading to identification of these successful well locations is discussed in length. More infill locations and well intervention opportunities are being identified by using this methodology with increased surveillance to further enhance production from this field.
Prediction of Water Influx of Edge-Water Drive Reservoirs Using Nonparametric Optimal Transformations
Authors: Al-Ghanim Jassim A. , Nashawi Ibrahim Sami , Malallah Adel 
Published: February 2012

Abstract
The accurate estimation of water influx into a petroleum reservoir is very important in many reservoir engineering applications, such as material balance calculation, design of pressure maintenance programs, and advanced reservoir simulation studies. These applications have heavily relied on the classical work of van Everdingen and Hurst for finite and infinite edge-water drive reservoirs. However, for both types of water drive reservoirs, the calculation of water influx is not a straight forward task. Table lookup and interpolation between time entries are needed, and furthermore for finite aquifers, interpolation between tables may be also required.
The paper presents nonparametric optimal transformations models for the prediction of dimensionless water-influx and dimensionless pressure drop for finite and infinite edge-water drive reservoirs using Graphical Alternating Conditional Expectation (GRACE). In order to achieve maximum efficiency, all the terms involved in the models are used in dimensionless form. GRACE transformations are totally data driven and do not assume any a priori functional form. The results of the various cases are in excellent agreement with the original tables of van Everdingen and Hurst.
Pressure Transient Analysis, Reservoir Parameters Estimation and Modeling of Kailashtilla Gas Field (Well no: 4)
Authors: Mohshin Md.. , Hossain Mohammad Shahedul 
Published: February 2012

Abstract
Vertical modeling, a tool based on theoretical background, simulates the pressure response in a vertical well within a rectangular shaped reservoir with homogeneous characteristics. The objective of this study is to perform pressure transient analysis to estimate reservoir parameters of kailashtilla gas field based on pressure and production data. A vertical model is matched to pressure history as an inverse process to extract the reservoir parameters and compared with the estimated and Al Mansoory Wireline Services resultant parameters. Deliverability test is performed to measure production capabilities.
Combination of Spirolizers and Spring Centralizers Reduces the Risk of Differential Sticking: Case Study of Wells in Shell Petroleum Development Company (SPDC), Nigeria
Authors: Anayo Okoronkwo , Timothy Ibrahim , Friday Otutu 
Published: February 2012

Abstract
Over the past 4 years, there have been several stuck incidents during installation of liners and casing in some wells in Shell Petroleum Development Company (SPDC), Nigeria. In most cases, the sticking mechanism was identified to be differential due to high pressure over balance across some depleted sand intervals. Attempt to free the casing or liner string was successful in few of the cases, while in others, it resulted in either cementing the casing in place at the stuck depth and deploying contingency option where they exist or going through the long, rigorous and expensive process of fishing, plugging back and sidetracking. Investigations into these incidents pointed mostly to the casing centralization.
During casing installation, a good standoff is required to keep the casing string away from the wall of the well bore to avoid differential sticking and achieve good cement placement. On the other hand, excessive centralization could lead to increased drag force particularly in deviated wells with the attendant risk of not getting the casing to bottom. Prior to casing installation, it is a standard practice to run simulation on centraliser spacing to achieve an acceptable standoff. Bow spring centralizers are commonly used especially for 9-5/8" casing installation and experience has shown that placement of these centralisers to achieve the acceptable standoff in order to avoid differential sticking as well as good cement distribution has led to having a casing string packed with centralisers thereby increasing the drag force. It therefore became imperative to develop a strategy for optimum centralizer placement in order to achieve both the acceptable standoff to avoid differential sticking and minimum drag. This paper discusses the approach taken to achieve this acceptable standoff with minimum drag force using a combination of Spirolizers and Bow spring centralisers and its impact in reducing the risk of differential sticking.
Case Study: Calcium Carbonate Scale Inhibitor Performance Degradation due to H2S Scavenger Injection in Semoga Field
Authors: Sumestry Meiliza , Tedjawidjaja Hendy 
Published: February 2012

Abstract
Semoga Field is an oil field in Rimau Block, which is located in South Sumatra, Indonesia. There is also a nearby oil field, Kaji Field, in this block. These fields experienced reservoir souring and suffered a history of calcium carbonate scale cases before a proper scale inhibition program was implemented. At the end of January 2011, there was a separation system problem at FWKO #2 Semoga Station. FWKO outlet lines were dismantled for inspection purposes, and it was found that the oil outlet line at the downstream of LCV was clogged by deposits, leaving only 0.5" of ID.
XRD and XRF analysis confirms that the deposit is calcium carbonate scale, even though routine scale coupon monitoring shows very low scale growth. There is H2S scavenger brand X injection at the downstream of LCV on FWKO#2 with a concentration of 11,050 ppm. The scale inhibitor dosage in the water line on Semoga Station was only 9 – 10 ppm. Laboratory simulation shows that H2S scavenger brand X injection reduced the scale inhibition percentage from 97.2% to 35.3%, with 9 ppm scale inhibitor. Meanwhile, no deposits were found in the oil outlet line at the downstream of LCV at Kaji Station, which has the same H2S scavenger injection point and dosage. Scale inhibitor dosage in the water line on Kaji Station was 17.5 - 22 ppm. Laboratory simulation shows that 20 ppm scale inhibitor resulted in a scale inhibition percentage of 58%. Laboratory analysis shows that the scale inhibition percentage increases linearly as the scale inhibitor increases under H2S scavenger brand X influence.
However, another laboratory test conducted using H2S scavenger brand Y shows that the scale inhibition percentage will decrease with the increase of scale inhibitor concentration, until it reaches the lowest value before increasing again with the increase of scale inhibitor concentration. Thus, the scale inhibitor performance in H2S scavenger brand Y influence behaves parabolically.
It is concluded that H2S scavenger injection increases system pH, resulting in the increased of scaling tendency. However, adding scale inhibitor concentration is not always the answer to overcoming scale growth resulting from this effect. It is important to understand scale inhibitor performance behavior on certain H2S scavenger brands before taking preventive measures. Scale inhibitor performance might have a linear correlation between increasing concentration and scale inhibition percentage, as shown by the behavior with H2S scavenger brand X, but it might also have parabolic correlation, as shown by the behavior with H2S scavenger brand Y or even other correlation types. A proper understanding of scale inhibitor behavior can prevent a production loss caused by the deposition of 8,190 barrels of oil.
First Application of a Lightweight Salt Slurry to Help Cement Longest Intermediate Casing across Salt Section and Improve Well Economics: Case History from the Gulf of Suez
Authors: Bhaisora Devesh , Paton Nestor , Waheed Arshad , El Nashar Radi , Farouk Mohamed , Soliman Fathy 
Published: February 2012

Abstract
This paper highlights a successful cement job in which more than 1,300 bbl of cement slurry was pumped to help cement the longest 9 5/8-in. casing in a highly deviated and washed out wellbore in the Gulf of Suez (GOS). This novel slurry design aided efficient cementing across a massive salt section, while mitigating the risks associated with using a multiple-stage cementing tool in highly deviated wells.
To access most of the reservoirs in the GOS, operators must drill through a salt section with a thickness sometimes greater than 1000 m. This section is covered with 9 5/8-in. intermediate casing, which is generally cemented in two stages using a multiple-stage cementing tool. Conventional salt slurries of 15.8- to 16-lbm/gal are generally used to cover the salt section.
Any failure with the multiple-stage tool can lead to expensive remedial work and can cause salt instability resulting from longer exposure, which can lead to salt creeping or loss of the well. The success ratio of multiple-stage tools is not high, especially in highly deviated wells; therefore, it was necessary to find a new approach to help mitigate the risks associated with using multiple-stage tools.
High-strength, low-density (HSLD) slurries have been successful in replacing conventional 15.8- to 16-lbm/gal slurries across the production zones. With this in mind, lightweight salt slurries were designed to replace conventional salt slurries across the salt section.
Because this is the longest intermediate casing in the GOS to date for the operator, it was logistically favorable because the lightweight slurries helped reduce the amount of dry cement required to meet the rig capability.
The cost of the multiple-stage tool, additional dry cement, dry-cement-transportation costs, and rig costs for waiting on cement (WOC) for the second stage were either completely eliminated or minimized with this solution, resulting in a total savings in excess of USD 100K.