bluuebunny/crossref_metadata_2025 huggingface dataset:
Potential Implementation of Casing while Drilling Technique in the Western Desert Fields of Egypt
Authors: Fattah K. A. , Sinde Seydou , Dahab A. A.
Published: February 2012

Casing While Drilling (CWD) technique allows the operator to simultaneously drill and case a wellbore section in only one run without the necessity to pull the drill string out of the hole. This innovative technique comes into play in time when oil and gas well drilling faces a lot of challenges such as excessive lost circulation, formation fluid influx, formation instability, etc. CWD is implemented into today drilling activities in order to safely and economically deal with these obstructive challenges. In addition to eliminating/minimizing the effects of these challenges, it remarkably improves the entire economics of the drilling project. Researches and developments are continuously on their ways to further improve the performance of the technique in order to minimize its limitations. A lot of case studies all over the world have been analyzed and their related practical lessons have been stated. Based on a study carried out on five shallow wells and seven deep wells drilled between 2007 and 2008 in the region of Western Desert, lost circulation and stuck pipe represented more than 80% of the drilling problems. The study revealed that CWD could be an alternative approach in the region to eliminate/minimize the aforesaid problems as was the case in numerous fields in the world. Therefore, the potential applicability of CWD technique in the region has been widely discussed. A proposed drilling program that suits CWD has been given. Special reference has been also given to casing string design, mud program, hydraulics optimization, bit selection criteria, working conditions and operational parameters such as WOB and RPM.
Challenge in Mature Field's Waterflood Project: Facing Limited GGRP Data & Budget Issue
Authors: Handayani Nuni , Simamora John H.
Published: February 2012

In the middle of high demand of oil production, Pertamina EP faces the fact that most of the fields are mature fields that sharp declining production rate is inevitable. This condition should be followed by other production method alternative because primary recovery is no longer be solution to increase production or restrain production decline. The option to this condition is moving to secondary phase: Waterflood.

EOR Department (team) performed screening analysis to find suitable candidates for the waterflood. Tapian Timur Field was one of the candidates. This field has a good potential to waterflood development but also has a huge constraint to be faced. Some constraints were the lack of GGRP Data, no existing water source, limited facilities and foremost was limited development costs. The challenge to develop waterflood project in this field is how to conduct project that meets engineering and economic aspect.

Tapian Timur Field's Study and Evaluation was carried out to evaluate Geology, Reservoir and Production in integrated way to determine: layers to be injected, injection patterns, sources of injection water, etc. The team also conduct comprehensive studies of production facilities. Due to budgeting issue, this project design emphasizes to maximally use existing wells and facilities. This could reduce costs significantly.

Waterflood was successfully conducted in layer C in May 2010 that preceeded with pilot waterflood. Pilot waterflood showed a good response indication. Currently the team is preparing POD (Plan Of Development) regarding to Tapian Timur Full Scale Waterflood Project.
Modeling Inflow Performance Relationships for Wells Producing from Multi-Layer Solution-Gas Drive Reservoirs
Authors: Qasem Fuad , Malallah Adel , Nashawi Ibrahim Sami , Mir Mohammad Irfan
Published: February 2012

Optimum field development strategy requires good knowledge of anticipated well performance and future flowing condition variation. This practice involves continuous monitoring of surface facility network, wells, and reservoir. Thus, it is crucial for the petroleum engineer to possess the appropriate tools to efficiently forecast well behavior, design artificial lift equipment and stimulation treatments, forecast production, and improve the entire production system optimization. Inflow performance relationship (IPR) is one of the vital tools required to monitor well performance. Currently used inflow performance relationship models are idealistic in nature, mainly developed for homogeneous reservoirs, and not suitable for multi-layer systems with different permeabilities. Consequently, the available IPR relationships do not provide accurate performance of such reservoirs. Thus, there is an urgent need for new realistic IPR models that describe the actual reservoir inflow performance behavior more efficiently than t he available models.

This study investigates the effects of reservoir heterogeneity on IPR curves for wells producing from multi-layer solution-gas drive reservoirs. To achieve the desired objectives a stochastic simulation algorithm known as simulated annealing was used to generate various permeability realizations among the stacked layers. The generated data were then thoroughly scrutinized and two simple yet accurate empirical IPR models were developed for heterogeneous two and multi-layer solution-gas drive reservoirs.
Chemical Injection in Multilayered Reservoir that have Different Rock Properties and Pore Pressures
Authors: Ahmed Quosay Awad
Published: February 2012

Well intervention techniques and several IOR and EOR methods are sometimes entailing injection of emulsion of water based chemicals and oil into hydrocarbon reservoir layers. The injection depth into each layer usually depends on a lot of different factors that related to reservoir rock and fluid properties as well as the difference between injected fluid's pressure and formation fluid's pressure. For a well completed in multi zones and each zone has its own permeability, porosity, fluid saturation and pore pressure; it is difficult to predict how and up to what end the injection fluid will invade each zone.

A computation model, based on analytical equations of flow in porous media, is developed to simulate bullhead injection of water based chemical solutions into well with multi opened zones. Analytical equations are developed to model fluid penetration radius, injected volume and injection rate for every opened zone during the injection process. Equations describe cooling effect of the injected fluid into hot formation is arranged and simulated to illustrate radial and vertical cooled area during the injection process. An equation is developed to simulate dilution process of chemical concentrated solution during its injection into reservoir layer

This model is very useful when it comes to plan and to design chemical water shut off, sand consolidation, microbial fluid placement, injection of mobility control fluids or any treatment involves of bullheading of chemical concentrated solutions into multi layered reservoir. It can be also used to design many workover applications especially for comminglely completed wells.
Modeling Flow of Chelating Agents during Stimulation of Carbonate Reservoirs
Authors: Mahmoud M. A. , Nasr-El-Din H. A.
Published: February 2012

Different fluids have been introduced in the oil industry to be used as alternatives to HCl. Chelating agents such as EDTA (ethylenediaminetetraaceticacid), and HEDTA (hydroxy ethylene diamine triacetic acid) have been used as stand-alone stimulation fluids. These fluids can be used to stimulate water injectors, oil, or gas producers, therefore, the effect of the type of reservoir fluid on the stimulation process should be investigated.

In this study, an analytical model was developed to describe the flow of HEDTA and EDTA chelating agents and propagation inside carbonate formations. The analytical model can be used as a pre-design tool before the treatments. The developed model can be used to predict the volume of the chelant solution required to create wormholes in calciteformations at different temperatures. The temperature affects the diffusion coefficient of the chelating agent, wormholing rate, and wormhole shape and size. The dissolving power of different forms of HEDTA chelating agent can be determined using the model. The optimum injection rate based on optimum wormholing conditions was identified for the chelating agents. Also, the model can be used to predict the wormholing rate of different chelating agents in carbonate formations.

The analytical model can be used to predict the performance of the chelating agent in carbonate stimulation. The volume of chelating agent required to stimulate carbonate formation per foot thickness was determined using the developed model. The optimum injection rate was determined for different chelating agents using the model and the results were compared with experimental results from previous work and there was a good agreement between the measured and the predicted values. The model can be used to determine the best stimulation fluid based on the temperature and fracture pressure of the target zones.
Comprehensive Model for Flash Calculations of Heavy Oils Using the Soave - Redlich - Kwong Equation of State
Authors: AL-Jawad Mohammed S. , Hasan Omar F.
Published: February 2012

One of the main techniques to achieve phase behavior calculations of reservoir fluids is the equation of state. Soave - Redlich - Kwong equation of state can then be used to predict the phase behavior of the petroleum fluids by treating it as a multi-components system of pure and pseudo-components. The use of Soave – Redlich – Kwon equation of state is popular in the calculations of petroleum engineering therefore many researchers used it to perform phase behavior analysis for reservoir fluids (Wang and Orr (2000), Ertekin and Obut (2003), Hasan (2004) and Haghtalab (2011))

This paper presents a new flash model for reservoir fluids in gas – oil separation stations. The proposed model uses Soave - Redlich - Kwong equation of state for calculating vapor and liquid mole fraction after each separation stage of heavy oils. The form of Soave - Redlich - Kwong equation of state that used in this paper is the cubic equation for Z-factor. The solution of this cubic equation depends on using Newton's and false position methods to find the three roots of the equation. This model finds the initial guess of Z-Factor using the false position technique and calculates the exact value of Z-Factor by applying the Newton-Raphson technique. The new model distinguishes between liquid and vapor phases through choosing the minimum root as the Z factor for the liquid phase and the maximum root as the Z factor for the vapor phase.

Many empirical relationships have been applied to calculate the related parameters which are utilized to perform the flash calculation. AL–Dulaimy's correlation (2002) is utilized to calculate the critical properties for the plus fraction (C7+). Wilson's correlation (1968) is used to guess the initial value of equilibrium ratio. Whitson's correlation (1984) is employed for calculating boiling point for plus fraction (C7+).

The new model has been tested using Iraqi oils data for several degasing stations. Calculated results of vapor mole fractions are found to be in excellent agreement with the field data. The graphical demonstration of the calculated results and field data shows credit index to utilize the new model in separation calculations of heavy oils under different temperatures. Two more Iraqi separation stations have been used to check the efficiency of the proposed model.
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

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

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

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 (>26%) at high temperatures (>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

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

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

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

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

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

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

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

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

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.
An Integrated Parameterization and Optimization Methodology for Assisted History Matching: Application to a Libyan Field Case
Authors: Al-akhdar Salem , Ding Didier Yu. , Dambrine Marc , Jourdan Astrid
Published: February 2012

Assisted history-matching is now widely used to constrain reservoir models. The objective of history match process is to improve the model in order to reproduce the production history while honoring the structural properties of the geological model. For that purpose, an objective function is defined in order to measure the mismatch between the simulation results and the production history. This objective function is usually minimized using a gradient-based optimization algorithm. However, history-matching of a large number of parameters in hydrocarbon reservoirs is a challenge because of several reasons: scarcity of available measurements relative to the number of unknowns, computational effort required for large reservoir and the need of insure that solutions are geologically realistic. All of these problems can be helped by using algorithms that rely on efficient and parsimonious descriptions (or parameterizations) of reservoir properties.

In this work, a history matching methodology is presented. First, a sensitivity study is performed for identifying the most relevant inversion parameters affecting the history-matching. The gradual deformation method is applied for the parameterization. Then, a new optimization technique, based on data partition for the gradient calculations, is studied for regional and well level history matching. The objective function is first split into local components, and the principal parameters are reduced for each component. In this context, we can propose perturbation designs with a smaller number of perturbations for the gradient computation. The proposed new technique is successfully applied on a real case in Libya in an integrated workflow, which makes history-matching with a large number of parameters tractable.
Increasing the Efficiency with Wireline Formation Testers and Reducing the Fluid Uncertainties in Thin-Laminated Low Permeability Reservoirs with in the Western Desert, Egypt
Authors: Ardila Mario , Ahmed Ramy , Dumont Hadrien , Naguib Mohamed , Zabcik Jim
Published: February 2012

Many sedimentary features of hydrocarbons at Western Desert are characterized as multilayered, deltaic, thinly and tight laminated sandstones consisting of sands with limited lateral and vertical extension. Relying only on conventional openhole log data and performing correlations among nearby wells proved to be inconclusive in identifying hydrocarbons reservoirs owing to their thin beds, high shale content, and variable formation water resistivity. Missing hydrocarbon-bearing formations translates into lost productivity, while perforating water zones can have detrimental effects on well performance.

Given these complexities, fluid identification and pressure measurements have a significant impact in resolving key uncertainties of such reservoirs. The main challenges faced during wireline formation testing in the reservoirs studied have been a) laminated, low mobility and thin formations with varying water salinity, b) no representative fluid samples due to deep mud filtrate invasion, c) eventual formation damage while drilling

The pretest/sampling efficiency with wireline formation testers and by using single probes has been traditionally very low in thinly laminated reservoirs because of the high possibility of dry or tight tests with long pressure stabilization time and not sampling or high contaminated samples. To displace invade fluids in low permeability formations can be challenging, usually requiring a high drawdown to pump the move filtrate from formation. To improve the job efficiency, High Performance packers and pumps are essentially in such environment that reduce significantly the differential pressure while pumping and increase the envelop to test zones beyond capabilities with the single probes. The Interval Pressure Transient Tests (IPTT) technique has been recently launched to increase the success ratio of wireline formation testers in getting reliable pressures and fluid analysis, including real-time monitoring of each survey by reservoir engineers.
Novel Rheological Tool to Determine Lost Circulation Materials (LCM) Plugging Performance
Authors: Kulkarni Sandeep , Savari Sharath , Kumar Arunesh , Jamison Dale E.
Published: February 2012

Lost circulation (LC), complete loss of drilling fluids into subterranean formations through natural/induced fractures, is a recurring problem costing the industry millions of dollars annually. Numerous solutions and drilling practices are applied in the field to mitigate, prevent or cure LC. Among these, the application of lost circulation materials (LCM) in the drilling fluids for plugging flow paths has been a widely accepted practice. LCM like ground marble, graphitic carbon and fibers are well-known to the industry. Different outcomes have been reported in laboratory tests and field applications when LCM is used in aqueous drilling fluids (AF) as opposed to non-aqueous drilling fluids (NAF). The present work provides a novel rheological tool to distinguish plugging performance of fiber-laden LCM in AF and NAF.

The LCM plugging performance is determined by conducting tests on permeability plugging apparatus (PPA) using a tapered slot (TS) on combination of fibers and particulates like ground marble and resilient graphitic carbon. It was observed that several combinations of fibers and particulates formed a plug in TS with minimal fluid loss in aqueous drilling fluids; however, when tested in NAF, LC was difficult to control.

To investigate the above performance difference, tests were conducted with an Anton Paar rheometer. Rotational rheometry is performed to measure first normal stress difference (N1) at low and moderate shears. It is found that the fiber contribution towards N1 in aqueous fluids is remarkably different from that in NAF. Microscopically, this difference in N1 could be attributed to the distinct fiber properties and orientation in these two systems that explain their contrasting performance in PPA analysis. Thus, the rheological technique provides a tool to identify LC control ability of the fiber-laden LCM system and optimize the concentration of fibers and LCM during the planning phase of drilling fluids.
Broadband Seismic: The Ultimate Input for Quantitative Seismic Interpretation?
Authors: Reiser Cyrille , Anderson Euan , Balabekov Yermek
Published: February 2012

Ideally, geoscientists would like to have quantitative information about rock properties, along with information about fluid content of potential reservoirs relatively directly from the seismic as this information is available as oppose to the well data. Historically, seismic images have stopped short of delivering this, as the seismic bandwidth was limited due to the conventional streamer design and acquisition method.

The ability to predict reservoir properties away from the well using seismic information is a key element in quantitative interpretation. Quantitative seismic interpretation combines various types of data: well, seismic and seismic interpretation or geological prior information. Thus, this workflow is integrated and the quality and accuracy of each individual constituent is of great importance to the accurately estimate the volume of hydrocarbon in place in a particular reservoir interval.

Seismic plays a key role in this, and if the seismic data contains very strong low frequency information and the seismic image is of high quality/resolution, it is possible to directly estimate the absolute impedance at each point within a seismic volume.

Over the last few years, new acquisition methods and technologies exist aiming to provide a broader seismic bandwidth: streamer towed shallow at the front and going deeper at the mid of the streamer, towed acquisition with some streamers at shallow and deeper depth, and the dual-sensor towed streamer.

These new broadband seismic data volumes are bringing the seismic a step closer to the reservoir and this is what we will try to demonstrate in this presentation. We will have the latest look at some of the newest and most exciting improvements in reliably unraveling the rock properties from the 3D seismic data.
Multiple EOS Fluid Characterization for Modeling Gas Condensate Reservoir with Different Hydrodynamic System: A Case Study of Senoro Field
Authors: Suwono Sugiyanto Bin , Hendraningrat Luky , Febrianto Dwi Hudya , Nugroho Bagus , Marhaendrajana Taufan
Published: February 2012

A proper analysis and fluid characterization is an essential key for successful modeling the behaviour of gas condensate reservoir. This paper demonstrates a robust multiple equation of state (EOS) modeling process for gas condensate reservoir at Senoro field. Senoro is a new major gas condensate field in East Indonesia with estimated IGIP greater than 2 Tcf and CGR range from 3-80 STB/MMscf. Senoro field is divided into two structures: the northern part is a carbonate reefal build-up, namely Mentawa, member of Minahaki formation, and the southern part is a platform carbonate Minahaki formation. The hydrodynamic condition in both formations poses a challenge to fluid characterization, where Mentawa member has both oil and gas with active aquifer, while Minahaki formation only has gas bearing rock with aquifer.

Senoro field has collected 36 samples, measured from down-hole and surface. The samples also cover composition analysis for surface recombined fluid. The required laboratory experiment such as CCE, DL and CVD have also been measured. The mathematical recombination was performed as a quality check to measure well-stream composition.

Two EOS models have been developed successfully to determine physical properties and to predict the fluid behaviour of Senoro. The heptanes-plus fraction is split into three pseudo-components to characterize fluid using Gamma distribution model. The fine-tuned fluid properties from all available data match both EOS models satisfactorily. These EOS models have also been matched with historical single radial welltest model. Compositional grading has also been developed to generate compositional map.

These established EOS models are used for compositional simulation. The gas and condensate profiles now could be predicted for optimizing field development plan. The use of EOS models can lead not only to a further field development strategy, but also to optimize the surface processing facilities.
Assessment of Unconventional Shale Reservoir: The Fegaguira Fm, Chotts Basin, Tunisia
Authors: Rezouga Nawel , Mohamed Anis Belhaj , Saidi Moncef , Bouazizi Ibrahim
Published: February 2012

Geochemical data indicate that the Late Silurian-Early Devonian Fegaguira Formation is the main source rock that has been charged the Ordovician and the Triassic reservoirs in the Chotts basin, South of Tunisia. Its good to excellent geochemical characteristic and its convenient maturity range allow it to be nominated as a good shale reservoir.

The reservoir assessment was based essentially on geochemical and mineralogical elements including: (1) source-rock distribution, thickness, organic richness, maturity level, petroleum generation and migration; (2) organic facies distribution, quality and kerogen transformation; and (3) mineralogical assessment, clay type and quartz richness.

A geochemical database consisting of 224 cuttings samples of the Fegaguira Formation was used to determine its geochemical characteristics including mineralogy. The examined shales show different thickness distribution that decreases towards the south east. They were subdivided into three distinct units according to their diagraphic responses, lithology and organic richness. The two upper units exhibit good total organic carbon averaging 5%, an original hydrogen index averaging 560 mg HC/g of TOC suggesting that the Fegaguira Formation was originally rich in type II organic matter (oil and gas prone kerogen), maturity ranges from 0.7 to 1.1 % R0, transformation ratio is about 0.78% and quartz richness up to 16%.

Detailed framework studies in petroleum geochemistry, lithostratigraphy and mineralogy combined with conventional modeling were used to estimate the unconventional oil and gas resources of the Fegaguira Formation.

The important organic content, the carbon transformation ratio, the gas derived both from kerogen cracking and oil-to-gas cracking, including the calculated porosity and the quartz percentage suggest that the Feguiguira Formation is a promising reservoir.