bluuebunny/crossref_metadata_2025 huggingface dataset:
New Acid-Diversion Technique Helps Stimulation of Production and Injection Wells—Case Histories from Egypt
Authors: Hamdy Mostafa , Taha Islam , Waheed Arshad , el Masry Yasser , El Eraky Hesham , Hanafy Khairy
Published: February 2010

One of the critical measures of success in matrix acidizing is having the acid distributed across all the zones of interest, thus ensuring they are all stimulated. This applies to production and injection wells where most zones are not homogeneous in terms of permeability, porosity, water saturation, or the degree of damage they have experienced; therefore uniform distribution of acid during the acid job is seldom achieved. For producing wells, this task is further complicated when high water-saturation zones form part of the pay interval; not only do the producing zones get inadequate stimulation, but the water zones get preferentially stimulated to produce large quantities of unwanted water that can kill the well or increase the lifting and disposal costs for the well.

Many acid-diversion techniques, mechanical and chemical, are available to help achieve even distribution of acid, but addressing water control and stimulation of the preferred zones in one treatment is uncommon. A new acid-diversion technique using associate polymer technology (APT) applied in the western-desert region of Egypt achieved tremendous results when compared to similar wells treated in the area. In one case, the production results from the well treated with APT were as high as 5,000 BFPD with negligible (0.02%) water cut compared to another well that produced similar fluid quantities, but with more than 50% water cut.

This paper discusses the first use of APT technology in the Al-Amein dolomite reservoir of Egypt and compares it with the earlier uses of other diverting methods in the same field. This same diversion technique was also recently used in another carbonate reservoir Abu Roash "G" (in the same field) on an injector well and it improved its injectivity index eight-fold. These successful stimulation case histories from the two reservoirs are elaborated in this paper.
Relative Permeability Modifier Fracturing Technique Inhibits Post-Fracturing Water Production: Case Histories from Egypt
Authors: Ali Ahmed , Yassine Rami , Waheed Arshad , Aal Ezz Abdel , Monsef Mohamed Abdul
Published: February 2010

Hydraulic fracturing has been extremely successful in the western desert of Egypt, with approximately 85% of the production resulting from the use of this stimulation technique. However, in many cases, the proximity of producing zones to underlying (or overlying) water zones can be a deterrent to fracturing. In the absence of geological barriers, the fracture height can grow uncontrolled during a fracturing treatment into the water-bearing interval and cause unwanted water production. By shortening the well's production life and increasing disposal and lifting costs, excessive water production can be extremely detrimental in marginal fields.

This paper presents case histories in which wells were hydraulically fractured using conventional techniques, resulting in higher than 60% water cut, and even as much as 100% in one case. While using the conformance-while-fracturing (CWF) method, the water cut was as low as 4%, even when the adjacent water zones were within 20 ft of the perforations. This technique provides a tremendous boost to the economics and an effective solution to a field otherwise plagued with water overproduction. The CWF technique incorporates a relative permeability modifier (RPM) in the fracturing-fluids design. The RPM results in a reduction of effective permeability-to-water without significant changes to the relative permeability-to-oil. This paper discusses the properties of the RPM, the CWF job-design considerations, its field applications, and post-fracturing results in comparison to offset wells fractured conventionally. These techniques might be beneficial to other companies faced with similar water-production challenges.
A New Criteria to Predict Stuck Pipe Occurrence
Authors: Meschi M. R. , Shahbazi K.. , Shahri M. Pordel
Published: February 2010

Stuck pipe is one of the main problems in drilling oil and gas reservoirs. It usually occurs in high pressure wells and leads to tremendous delays and costs in Iran, every year. Even if different techniques and guidelines have been developed to reduce the probability of occurrence of this phenomenon and these have saved drilling industry millions of dollars, they suffer from exclusive prediction of this event. The reason is that some of these techniques such as sag register incorporate one drilling parameter such as mud weight only.

In this paper, mud logging and daily reports of 75 wells in one of Iranian Southwest oil fields were studied. The performance of wells that did not experience stuck pipe was compared with the performance of those that led to stuck pipe.

Mud weight, yield point, plastic viscosity, initial gel strength, Marsh funnel viscosity, dial reading at 600 rpm, solid content, temperature, washout and the period that pumps do not need maintenance were employed to introduce a new parameter called Reducing Stuck Index (RSI). It was found that RSI is proportional to the mud weight, initial gel strength; yield point, solid content and temperature and also inverse of plastic viscosity, Marsh funnel viscosity and dial reading at 600 rpm to the power of 0.3. For this field, the comparison of RSI of the current well with those of drilled wells predicted the probability of occurrence of stuck pipe very well.

Monitoring RSI helps the driller to know whether the drilling process results in stuck pipe. If the situation is leading to stuck pipe, the drilling parameters can be managed in such a way that RSI lies in the safe range and stuck pipe is prevented.
Formation Damage Kinetics and its Effect on Oil Reservoir Productivity
Authors: Mikhailov N.. , Chirkov M..
Published: February 2010

Formation damage, a common problem associated with field operations, is often a major factor in reducing the productivity and injectivity of a well in a petroleum reservoir. Numerous laboratory and field studies indicate that formation damage occurs during many phases of reservoir development – drilling, completion, workover, production, stimulation, water flooding, or improved oil recovery. Formation damage is a process of initial permeability reduction. At present many mathematic formation damage models are developed. These models contain a number of parameters that is difficult to determine and mostly are not appropriate for field usage. We offered a way from lab to field scale that takes into account the process of formation damage during reservoir development. Analyzing the results of laboratory experiments and formation damage studies we defined that permeability has similar kinetics of alteration for different damaging mechanism. Next we determined the principal damaging mechanisms of real oil formation and associated them with laboratory relations of permeability alteration. As a result the integrated relations of permeability reduction and the new model of formation damage were obtained. This method was used as a predictive tool for quantitative predictions of field development showings for different rock types and operation strategies. Equations of permeability kinetics were integrated into reservoir simulator. The effect of permeability kinetics on formation development process was shown concerning clay oil formation. Based on laboratory and field observations the methods of enhanced oil recovery and formation damage prevention were proposed.
Characterization and Simulation of a Complex Fractured Carbonate Field Offshore Tunisia
Authors: Bejaoui Riadh , Salem Ryadh Ben , Ayat Hamed , Kooli Imen , Balogh Dave , Robinson Gary , Royer Theodore , Boufares Taoufik , Ouenes Ahmed
Published: February 2010

This paper describes a workflow that fully utilizes the pre-stack and post-stack seismic attributes to derive reliable geologic and fracture models that are validated by multiple blind wells and reservoir simulation. The first step in the workflow is to run post-stack seismic processes, which includes post-stack inversion and spectral imaging. The second step consists of applying a pre-stack seismic process called elastic inversion which will lead to various key seismic properties that provide good discrimination between reservoir facies. The third step consists of using the various post-stack and pre-stack seismic cubes to derive 3D geologic and fracture models. The fourth step is to use the derived models in a reservoir simulator to verify the validity of the models.

This workflow was applied to a complex fractured carbonate field in offshore Tunisia which produces oil from the El Gueria formation. A large number of post-stack and pre-stack seismic attributes were generated in time and then depth converted within a 3D geocellular grid. These seismic attributes were used as input in REFRACT™, Prism Seismic fracture modeling software, to create geologic and fracture models. The resulting porosity and permeability models were put into Eclipse™ reservoir simulator software. Individual well performances were matched at eighty percent of the wells, confirming the reliability and accuracy of the derived geologic and fracture models and the usefulness of the workflow.
The First Successful ImpulseTest on Coiled Tubing Results in Reliable Reservoir Evaluation for Non-naturally Flowing Wells
Authors: Guichard Anna , Zhan Lang , Dilling Lambert , Giaquinta Alejandro , Mohamed Ezz Eldin , Awaad Ahmed Hamdy
Published: February 2010

In mature fields it can often be a challenge to obtain accurate well data and reliable formation parameters without imposing high cost and time constraints on development or production schedules. One common method to test non-naturally flowing wells is impulse testing, which makes use of differential pressures between the formation and a surge chamber or wellbore to perform a short flow period or surge test, followed by a relatively short shut-in period. Unfortunately, these tests frequently result in invalid or uninterpretable data as a result of several uncertainties and test constraints.

An improved version of this common technique encompasses a three-fold approach to optimize the impulse test. A new numerical simulator designs the test to maximize depth of investigation without compromising the interpretable data. The coiled tubing-conveyed intelligent bottomhole assembly used to execute the impulse test may, in certain environments, reduce operating times in comparison to use of conventional tubing-conveyed solutions. The combination of the prejob design package and a functional bottomhole assembly enables consideration of the complexities that can result from impulse testing so that a valid data set is delivered. The interpretation is performed using traditional well test interpretation methodology and an analytical solution specifically designed for impulse testing. This solution considers the wellbore fluid density variation during the test while still maintaining the simplicity of the wellbore model; variable skin is described by an exponential function, thus improving on established analytical methods. A comparison of the results from both interpretation methods establishes the test validity in terms of flow capacity and skin. This paper describes the systematic approach, including its design, execution, and interpretation, and highlights advantages and limitations through the case study and field data of a well in the Wadi Rayan field of Qarun Petroleum Company.

This technique offers a rigless testing method that can optimize test time while delivering valid, accurate results that aid in production forecasting, completion optimization, and planning of remedial intervention for non-naturally flowing wells.
Production Improvement of Formation Damaged Wells by Proper Acid Treatment
Authors: El-Halib Ismail Mohamed
Published: February 2010

Restoring the well's productivity from existing damaged or partially damaged formations has been the objective of many operators over the years. The damaged or partially damged formations requires to diagnose the causes of the damage in order to design the proper stimulation treatment to remove the damage and restore the well productivity. Drilling fluid, completion fluid and kill fluid have the potential to be the most damaging portion of reservoir life.
Integration of Pressure Buildup Deconvolution with the Rate-Normalized Pressure
Authors: Ortiz Rubiel , Davani Ehsan , Tran Tan , Sinurat Pahala , Ehlig-Economides Christine A.
Published: February 2010

Pressure transient analysis (PTA) is typically performed on pressure BU data acquired over a period from a few hours to a few days, while production data analysis (PDA) is performed with production data acquired over a period of a few days to several years. Recent approaches to extending a pressure BU response by deconvolving production data seem promising, but simple rate-normalized pressure (RNP) and its derivative may be more straightforward provided redundant data and artifacts are eliminated in the RNP processing.

This paper offers a unified PTA-PDA analysis combining pressure BU deconvolution with the RNP. Using the RNP as the indicator of the late-time behavior, the unified PTA-PDA analysis can provide a virtual constant rate drawdown response for the duration of the production data including the early time response from a selected pressure BU transient. The virtual pressure change and, in particular, its derivative provide trends easily identified as flow regimes suggesting model features that must be included in a simulated drawdown intended to match the unified response.

A model match with the virtual drawdown resulting from the unified PTA-PDA analysis offers a model consistent with the entire production history that can be used to forecast future production behavior and reserves for the well. Synthetic and field examples illustrate the approach.
Optimizing Simulation Studies for Gas Condensate Field Development and Management
Authors: El-Banbi Ahmed
Published: February 2010

Two field case histories to illustrate the techniques in simulation of gas condensate fields for field development and reservoir management are presented with emphasis on how to speed up the study work without reducing the accuracy of the results. One field case has been chosen as a "green field" development case, and the other as "mature" gas condensate redevelopment. Both fields were near critical reservoirs and an integrated approach was followed in developing the static and dynamic models.

For the green field case, the model was used to suggest new well locations and forecast production. For the mature field case, the model was used to optimize the performance of the field, increase recovery factor, and accelerate production. Several techniques were employed to facilitate the history matching and prediction runs. These techniques included the use of Modified Black Oil (MBO) approach, breaking down the model into smaller sectors to take advantage of isolated fault blocks and geological layers, a systematic procedure for history matching, and the involvement of field operation guidelines in designing the prediction runs. These techniques resulted in significant time savings in the study and allowed the study team to dedicate most of their time and effort to field development optimization. The model was changed to compositional model to investigate the effect of gas cycling and compare it to other alternative development plans. A detailed economical model was also built and coupled with prediction runs to select the most economical development plan.
Phase Behavior Aspects of Carbon Dioxide (CO2) Miscible Flooding in Tight Cores: A Case Study
Authors: Rahman Saifur , Nofel Wasef , Al-Majed AbdulAziz , Arshad Aziz , Menouar Habib
Published: February 2010

Carbon dioxide flooding process has been a proven valuable tertiary enhanced oil recovery technique. Although the petroleum industry has been applying the technique to produce heavy oil, it can be an effective tool to yield appreciable recoveries from complicated formations to produce comparatively lighter oil. The focus of experimental studies has been on the production of heavy oil and Carbon dioxide application to a wide range of other geological conditions and for wide range of petroleum fluids has been a less traversed path. Especially the process can be applied to tight formations where normal production procedures are not economically viable. This unviability may be due to rock or rock-fluid interactive properties. A research program for evaluation of the feasibility of development of such tight formations in the Middle East has been initiated. The research work included determination of minimum miscibility pressure (MMP), CO2 Core flooding and phase behavior investigation. Since both these processes are governed by the phase behavior; an investigation of phase behavior and PVT properties of reservoir fluids when combined with carbon dioxide are an integral part for a complete evaluation of crude oil extraction process. This paper presents the experimental and simulated phase behavior data for various mixtures of a live crude oil and carbon dioxide. The data helped in designing of the slim tube investigations and core flooding experiments.

The phase behavior during a CO2 flooding is a very complex process. Three mechanisms; oil swelling, reduction of oil viscosity, and the acidization of carbonate help obtaining better recovery in a CO2 flooding process. First two are the mechanisms boosting the miscibility between CO2 and reservoir oil. The other parameters which effect phase behavior during a CO2 flooding are the temperature, pressure and rock-fluid interactive properties of the reservoir. Carbon dioxide can be first contact miscible with crude oils, but usually at very high pressure. Attaining and operating a flooding process at these pressures is not financially desirable. Multi contact miscible process is preferred as the economical process for the carbon dioxide flooding.

The phase behavior of the original oil and after addition of different amounts of CO2 was studied by performing Constant Composition Expansion (CCE) tests. The bubble point pressure determined for the original oil sample and with increasing carbon dioxide. The phase behavior properties like bubble point pressure amount of liquid for the mixture with carbon dioxide range matched well with Equation of State (EOS) simulations. A comparison of the average density of the crude oil CO2 mixtures confirmed the swelling process. A material balance study between the injected and produced material from the core was also done for verification.
Optimizing Development Well Placements within Geological Uncertainty Utilizing Sector Model
Authors: Mesdour Rabah , Ramsey Lee , Aly Ahmed
Published: February 2010

Uncertainties particularly in geological parameters are always present and can be significant if associated with field development. These uncertainties could be perceived by geologists and engineers to exist in the available data. Industry has been using uncertainty analysis to identify, address and mitigate risk. Development strategies and well placement may significantly depend on field geology, maturity of the depletion stage, technological factor, drive resources and other parameters. Well placements optimization most of the time is done based on a deterministic (most likely) case. The optimum placement of wells within geologic uncertainty is the issue addressed in this paper.

This paper discusses a new approach and workflow process for applying uncertainty analysis using sector model of an undeveloped reservoir and the optimization of development wells under geological uncertainty. Tornado plots were used to identify the highest critical parameters among the list of uncertainties of the field. Experimental Design was used to select simulation runs to build the proxy model. Monte Carlo analysis was then used to generate the density distribution function of cumulative production to identify the P10, P50 & P90 cases. The probabilistic distribution was used to determine the likelihood of the development case under identified risk parameters. Field operation strategies were considered together with optimization of injector-producer spacing, producer-producer spacing, horizontal completion, well length and orientation with geologic uncertainties. The optimized development plan and well placements were used to generate the cumulative production distribution with uncertainty parameters. This workflow was successfully tested in a large carbonate field.
One Dimensional Modelling and Experimental Validation of Gelled Waxy Oils Restart
Authors: Margarone Michele , Borghi Gianpaolo , Correra Sebastiano
Published: February 2010

Flow restart after a planned or emergency production shut-down of waxy oil offshore pipelines is a concern to operators. Since reliable methods to predict the required time and input pressure are not available, there is a high risk to lose a transportation or production flow line. So far most of predictive models have been based upon the assumption that gelled crude behaves as an incompressible high viscous fluid. Field cases and laboratory model pipeline tests have shown however that these calculations give systematically overestimated restart pressures, giving the opportunity to lower investment development schemes (such as less insulated pipelines or no extra pumping requirement). Since offshore oil industry is facing more and more challenging production environments, such as deepwater and marginal fields with long tiebacks, this issue is becoming even more stringent, affecting directly the investment cost required for the development of waxy oil resources.

The aim of this work was to investigate the problem of restart of waxy crude oils and preliminarly to present a new mathematical model as a robust pipeline restart predictive tool with a sound physical basis. Although this topic has been investigated for more than forty years, until recently, when Vinay et al (2006, 2007) and Wachs et al (2009) developed a theoretical framework for start-up transients of compressible yield stress fluids, no one had considered the old and simple plastic Bingham Model (BM) (Bingham, 1919). Beyond the model description, a first analysis comparing model forecast with experiments carried out in a model pipeline with multiple pressure taps at constant injection flow rate was carried out.
Technology and Innovation: Do We Do Enough in Our Industry?
Authors: El-Banbi Ahmed
Published: February 2010

This paper compares the petroleum industry with other industries from the technology development aspect. The comparison is based on studying financial as well as Research and Development (R&D) investment data for the Fortune 500 companies.

Our industry has been coping with increased hydrocarbon demands by responding to increased challenges to find and produce more hydrocarbons through developing new technologies. Some of the historical key technologies in the petroleum industry are reviewed. The current challenges requiring new and novel technological developments in our industry are also highlighted.

We followed a systematic analytical approach to investigate and compare technology development in the petroleum industry with other industries through investigation of public company data for the Fortune 500 companies in addition to major petroleum and major service companies. The investigation reveals an interesting correlation between the profitability of a company and its R&D investment. Also, and within the same industry, companies which invest more in R&D seems to enjoy superior profits over their competitors. Although the oil industry invests significant amounts of money in technology development, it spends less than other industries in both R&D spend as percentage of revenue and the actual amount of money spend.
Control of Pressure Dissolution and Quartz Cementation on the Reservoir Quality of Glacial Ordovician Sandstones from the Sbaa Basin, Algeria
Authors: Tournier F.. , Portier E.. , Pagel M..
Published: February 2010

GDF SUEZ and Sonatrach will develop in partnership the main fields of the prolific Sbaa basin, SW Algeria. In this area, the main gas reservoir is composed by the glaciogenic Upper Ordovician, which exhibits high poroperm heterogeneities, with porosity and permeability ranging from 1 to 15% and 10−3 to 103 md respectively. The low permeability zones are generally encountered in the lower units of the reservoir and no obvious geological control has been interpreted so far. According to previous studies, quartz cementation and pressure dissolution are responsible for these low petrophysical properties. An extensive diagenetic study was then undertaken to understand the origin and the distribution of these diagenetic processes and their impact on the reservoir architecture (Tournier et al., submitted). It underlines the role of the glaciogenic processes, responsible of clay coating development in underlying clean sandstones. These clay coatings will determine afterwards diagnetic evolution of these sandstones by enhancing pressure dissolution. Produced silica is exported in low compacted upper layers and deposited as quartz cement (Tournier et al., submitted). In the present paper, two main petrofacies are distinguished by their dominant diagenetic features, either pressure dissolution or quartz cementation. This petrographical classification has strong petrophysical implication, and highlights the importance of these two diagenetic processes in the reservoir quality of these sandstones.

The two petrofacies described in this paper, QS1 and QS2, correspond to the distinction between conventional and tight reservoirs. The value of 5% porosity may be considered as the limit between the two types of petrofacies and provides a pertinent insight about porosity cut-off used in petrophysical properties evaluation of the glacial Ordovician sandstones of the Sbaa basin.
Shelf-to-Basin Floor Seismic Expression of the Rosetta System (Western Nile Delta, Egypt): A Modern Analogue of Deep-Water Reservoirs
Authors: Rouillard P.. , du Fornel E.. , Migeon S.. , Dauphin L.. , Mascle J..
Published: February 2010

The need of modern analogues is critical for petroleum exploration, mainly for deep-water reservoirs because of their wide variability in term of size, thickness and lithological lateral changes that make them still difficult predict. Analyse of geometry and stacking pattern of "recent" (Plio-Quaternary) sedimentary bodies can greatly improve our ability to understand buried reservoirs. Because the Nile submarine delta is the largest area of gas exploration and production of the Mediterranean and because its recent history, architecture, source and factors controlling the sediment dispersion are now well constrained, the Rosetta turbidite system (western province off Nile Delta) is probably the best site to study of a silty/mud delta-fed turbidite system. The main goal of our approach is to propose a conceptual model of a delta-fed turbidite system construction and evolution through time.

A wide 2D and 3D-seismic data set from the shelf to the basin, respectively provided by GEOAZUR laboratory and GDF SUEZ was made available over the whole Rosetta system (western province of the Nile fan, off Egypt). Numerous sedimentary bodies have been characterized and discriminated along a dip synthetic profile and replaced within a relative chronological framework to build a depositional model of the system and to provide new insights on the architecture and stacking patterns of deep-water reservoirs.

The Rosetta system appears to be a rapid point-source migrating system driven by large-scale slope failures and sea-level fluctuations. During sea level falling stages, sediment transfer is constrained and channelized by scars at the shelf break resulting in the construction of small channels indenting the top of mass-transport deposits and depositing ponded lobes in topographic lows. As sea level drops, a short and narrow submarine canyon is progressively formed and the turbidite system progrades toward the basin floor. Sea-level lowstands favour the development of wide shelf-margin deltas, which are feeding and prograding over the canyon head that rapidly evolves in an unconfined meandering leveed channels system. Avulsion processes affect these leveed channels systems as the slope gradient changes due to regional salt-tectonics, crevasse splays, and they deposit wide distal-lobe complexes at their mouths.

This model might be used as a predictive model for gas reservoirs for the Kafr El Sheikh and El Wastani formations in the western part of the Nile Delta and, more generally, for any other unconfined delta-fed turbidite systems.
CCS Project in a Gas Field of the Sbaa Basin, SW Algeria - What is at Stake?
Authors: Mossé Y.. , Portier E.. , Schaaf T..
Published: February 2010

GDF SUEZ and Sonatrach will develop in partnership the main fields of the prolific Sbaa basin, SW Algeria. In this basin, the main gas levels comprise the Cambrian and Upper-Ordovician reservoirs, sealed and sourced by the Silurian "Hot Shales" Formation. Average CO2 content of raw gas is in excess with regard to sales gas specifications. As a result, CO2 removal is required as part of gas treatment and it is intended to install an amine unit in the future Central Processing Plant for such purpose. Regeneration of the amine results in the release of significant quantities of CO2, which amounts to ca 1200 t/day. Looking for a solution to re-inject underground this CO2 was decided, within the project exploitation perimeter. Such an initiative has materialized with the achievement of a screening and feasibility study during the development conceptual phase, which identified the two best structures for underground CO2 sequestration. In both cases, CO2 should be re-injected in the aquifer, in the water leg, away from gas production area. A pilot well will be drilled to address the geological and reservoir uncertainties, so as to validate the concept.

For now, preparatory sensitivity studies, using Cougar® software (developed and marketed by IFP) were performed to identify key parameters controlling the CO2 re-injection performance. These probabilistic results show that, if effective permeability and reservoir heterogeneity are from far the main drivers, the mobility of fluid in place, such as gas or formation water, strongly controls the performance, ranging from 55 to 98 % of CO2 to be injected. Based on experimental design type of approach, this study enable to rank the main uncertain parameters (such as type of wells, number of injectors and maximum operating pressure) and to quantify their respective contribution to the underground CO2 storage performance.

This type of study helps to determine the priority in the data acquisition program of the future pilot well and to set-up the basis of design of the CO2 sequestration facility.
An Improved Grey Relation Analysis Method and Its Application in Dynamic Description for a Polymer Flooding Pilot of Xingshugang Field, Daqing
Authors: Feng Y.. , Ji B.. , Gao P.. , Li Ye
Published: February 2010

The industrial experience at Daqing showed that chemical flooding significantly could enhance the oil recovery. Meanwhile, the fluid behaviors in the reservoirs became more complex due to the injection of chemicals. The dynamic connectivity between injection and production wells formed by water flood has been changed significantly due to the participation of chemical solutions. In this research, an improved grey relation analysis method (IGRA) is introduced to predict the dynamic connectivity between injection and production wells and to estimate the effects of connectivity changes. Plenty of sensitivities in chemical floods are considered in this new method so that the influence of errors caused by a poor indices choice in the variable process description can be minimized. An application was carried out in a polymer flooding pilot of the Xingshugang Unit, Daqing. By comparing the results of both the water and chemical flooding prediction results with IGRA, the dynamic connectivity changes have been demonstrated. Tracer tests have been conducted for both water and chemical flood. The interpretations of the tracer tests have also proven the accuracy of predictions. The results of chemical flooding prediction have been used to adjust the injection and production rate for individuals.
Application of Group Method of Data Handling for Geological Modeling of Vankor Field
Authors: Semenov A. A. , Oshmarin R. A. , Driller A. V. , Butakova A. V.
Published: February 2010

One of the main issues while reservoir geological model creation is to establish the relationship between measured rock properties (e.g. porosity, permeability) and well logs values. Standard approaches consist in using deductive mathematical modeling algorithms to solve this problem. The primary objective of this study was to develop the best mathematical model for Dolgan reservoir rock characteristics estimation using all available well logs information. It is obvious that simple polynomial models for this area were not applicable due to special properties of water saturated. Matched rock properties lab measurements in reference wells and well logs data were available.

In the frameworks of this article several statistical methods including various regression types and neural networks were analyzed. The best relation in terms of statistical criteria was obtained by the group method of data handling (GMDH) method. GMDH is an inductive modeling algorithm using neural network with active neurons. This approach optimizes not only model coefficients for predetermine mathematical equation but also select optimal model complexity.

Multilayered algorithm of GMDH, based on polynomial reference function allowed maximizing amount of information being used from different types of well logs in reference wells for target relation. Data from neutron, density, resistivity and PS logs were the most significant for the final model of Dolgan resorvoir.

So using of GMDH cybernetics algorithms may significantly increase precision of rock properties forecast for further geomodeling purposes.
Overcoming Uncertainties Through Advanced Real-Time Wellbore Positioning in Kuwait: A Success Story
Authors: Jumah Saud , Saleh Khaled , Al-Mayyan Haithem , Al-Mudairis Fahad , Hawkins Don , Al-Abri Hakim , Martinez Pavel
Published: February 2010

Real-time multi-lateral wellbore positioning of horizontal wells for improved reservoir deliverability has been a revolutionary breakthrough worldwide. It has supported the efficient production of hydrocarbons from multiple thin layers within a reservoir to yield maximum recovery and to restrict water coning. Recent advances in real-time geosteering now enable, with even greater precision, successful targeting of "sweet spots" within a reservoir. These advances have the capability to open still more drainage volume for recovery of hydrocarbons.

Through successful teamwork from multidisciplinary professionals, numerous uncertainties and challenges were overcome using real-time geosteering techniques in conjunction with advanced logging-while-drilling (LWD) sensors and instrumented rotary steerable systems in Kuwait Oil Company's Magwa field. For this purpose, pre-well modeling, real-time geosteering, advanced LWD sensors, including azimuthal deep resistivity (ADR™) sensor, an azimuthal lithodensity (ALD™) sensor, instrumented rotary steerable systems (RSS), and real-time operation (RTO) services were used. The historically anticipated production rate was surpassed through the optimized placement of this well.

The outcome of this particular dual-lateral well using advanced real-time geosteering technology has led to development plans for additional multi-lateral wells in Kuwait. They will be targeted to the highest porosity and permeability zones within the upper compartments of the reservoir while avoiding the adverse water coning effects of wells drilled vertically or in the massive sand. This paper reviews the teamwork and deployment of real-time geosteering operations, as well as new generation LWD and RSS sensors, used to successfully improve reservoir deliverability.
Real-Time Well Tool Face Information Reduces Directional Uncertainty and Risks in Difficult Sidetracks in Gulf of Suez
Authors: Howes Thomas B. , Farouk Mohamed , Darwish Mohamed , Koroletz Wilhelm , Ismail Ahmed , Moustafa Amin , Heisig Gerald
Published: February 2010

To address risk and uncertainties in difficult sidetrack operations in the Gulf of Suez in Egypt, a new method was implemented to identify and control the direction of the wellbore during the whipstock exit, and close to the liner, where standard directional measurements are compromised due to magnetic interference. Bending moment sensors were placed directly above the motor and only 26 ft behind the bit. These sensors delivered two perpendicular bending moment measurements referenced to gravity high side. Transmitted to surface via mud pulse telemetry, the two signals were further processed to deliver the well tool face and – with the help of a mathematical BHA model – the dogleg severity of the well.

In one case the well tool face confirmed the orientation of the whipstock and the window milled. However, in a second case, the measurement revealed a 40 degree deviation from the original whipstock orientation. The well plan was immediately adjusted to compensate for this deviation from plan. The dogleg severity information gave improved azimuth control when steering away from the existing well in sliding mode. As a result, both sidetracks achieved their directional objectives and could be steered into the target. The directional estimates derived from the bending moment measurements were later confirmed by the first valid MWD surveys and by gyroscopic survey measurements.

The paper will start with a detailed description of the directional challenges in this application. It will then introduce the concept of the bending moment measurements and the derived directional information, well tool face and dogleg severity. After a description of the implementation and directional execution of the sidetracks, the paper will conclude with a discussion of the benefits and the potential of this new directional control method, which could result in a reduction or even complete elimination of gyro runs during similar casing exits and significant rig time savings.
Intelligent ESP System Enabled Effective Stimulation and Post Treatment Well Test: A Case Study of Restoring Production from a Horizontal Well in Belayim Marine Field
Authors: Soegiyono R. E. , Guichard A. M. , El Sonbaty A.. , Dilling L.. , Crema G.. , Pierfelici S.. , Mahmood A.. , Fawzy A.. , Abuzeid M. E. , El-Farahaty Osman M. M.
Published: February 2010

Intelligent artificial lift technology is increasingly being used in Belayim Marine Field to enhance the value of maturing assets and new development wells. Wells equipped with electric submersible pumps (ESPs) are particularly suited to this blend of old and new. For years, the performance of ESPs has been monitored and controlled from the surface to prevent early pump failure by adjusting the frequency of the signal sent to the pump's variable speed drive (VSD) motor controller. This adjustment has also been used to avoid under-loading an ESP and increase production volume. To find this optimal operating range, real-time data and modeling are used to design the pump to fit the specific requirement of each well.

Most recently, Belayim Petroleum has taken the concept a step further by deploying intelligent artificial lift in combination with stimulation technology aimed at reservoir management to help restore production from the 113-M-97-H well in Belayim Marine field, which is located in the central part of the Gulf of Suez, along the coast of the Sinai Peninsula. This new development well was drilled horizontally with maximum angle of 88°, and a 211 m. horizontal open-hole section was completed with 3.5-in. excluder screens. The well once achieved 22-hour good recovery at 550 BOPD. Then the production declined and the well was shut in due to low amperage, followed by no recovery caused by severe loss of circulation, which created a filter cake plugging the near wellbore pores. Complex stimulation treatment and flow, and well geometry and completion, as well as the offshore environment have complicated workover operations on this depleted reservoir and unproductive well issues. With intelligent ESP, a cost-effective stimulation was successfully deployed and enabled to evaluate production streaming data, such as pump intake pressure and temperature during the treatment across the horizontal section.

Already equipped with in-well electric power cables, protectors, and multi-sensors, as well as a power controller VSD at the surface, this intelligent ESP system also enabled clean-out process at different production rates. Once clean reservoir fluids were observed during the flowing period, the ESP was stopped for a pressure build-up. A post-stimulation well test was performed to evaluate the treatment's effectiveness before running the new completion, hence minimizing intervention time to restore production promptly, reducing rig time, and achieving optimum completion design for long-term productivity of the well.
Gulf of Suez Continuous Gas Lift Real-Time Optimization Strategy
Authors: Abdallah Yasser A. , Gaber Nabil S. , Saad EmadEldin A. , Bedair Elsayed A. , Soegiyono R. E.
Published: February 2010

The application of continuous-flow gas lift systems have been operating for over 40 years in Gulf of Suez Petroleum Company (GUPCO) offshore Gulf of Suez. Like any artificial lift method, it is to improve the productivity whilst ensuring the most effective use of the existing reserves. Continuous gas lift operations is favorable for these fields because of the flexibility in its production rates, ability to handle corrosive fluids, suitable for high temperature and high gas oil ratio wells, and compatibility with sand production. Some other real challenges facing the Gulf of Suez assets management besides keeping up production and maximizing reserves from mature fields are the ageing production facilities, and limited testing and data acquisition infrastructure. As more and more wells are completed with gas lift, the task of gas lift monitoring becomes more time consuming.

An important part of the gas lift optimization process is the effective gathering of live field data in order to establish the performance of the field and its individual well. A source of this information so far is a bunch of well files placed in the field and or head quarter offices. Because of inadequate infrastructure for an optimization and monitoring schedule, it is required to initiate a system with today's real-time data acquisition and data transmission technology, which provide an opportunity to implement the real-time production optimization effectively and remotely by means of satellite and web interface.

A pilot platform was selected to prove the concept of real-time production optimization. It is located in El-Morgan offshore field, approximately 160 miles in the south Gulf of Suez. The field consists of four (4) major platform complexes and 17 satellite platforms with over 80 current producers and around 50 injectors. Despite on-going operational difficulties and complexities, waterflood operations in this field indicate a successful exploitation of potential reserves. The field's cumulative production to date is 51% of its predicated Stock Tank Oil Initially in Place (STOIIP). Manual data gathering exercise is being implemented as a remedial solution to validate definitive benefits from the gas lift optimization process. The pilot began with a feasibility study for most reliable, safe and secured data acquisition and data transmission deployment to overcome the daily struggle of gathering sufficient, current and reliable data, and to better understand the field production potential. The strategy is further defined into several steps from efficiently monitor well behavior on a well by well basis, achieve full monitoring coverage for the field, provide quick response to well down-time, provide thorough review and analysis on well performance, hence give more time to gas lift engineers to look for other optimization opportunities around the field.
Latest PDC Technology and Optimization Process Enable Replacement of Multiple Impregnated and Roller Cone Bits with One PDC Bit Run
Authors: Foucault Hubert , Malagon Raul , Aliko Enis , Teelken Reina , Hitchman Ross
Published: February 2010

The Cambro-Ordovician formation in onshore Algeria consists of hard and abrasive sandstones that have proven challenging to drill. Up until now, no bit has completed the section in one run, and these formations have been considered beyond the limit of what is drillable by PDC cutters. Previous sections have used impregnated diamond and roller cone bits that achieved low penetration rates and required multiple bit runs. The impregnated runs require the additional cost of turbo drills or high-speed motors to deliver the rotation speeds necessary to achieve acceptable rates of penetration, while a bearing seal failure of a roller cone bit increases the risk of losing bit pieces in hole.

The operator conducted an optimization process based on rock mechanics including an analysis of prior performances to conclude that the formation could be drilled more economically applying the recent advances in PDC bit technology. Collaboration between the bit manufacturer and the operator facilitated the implementation and development of the latest bit technology, including enhanced bit stability, improved cutter layout and more resistant cutters. After an initial, partially successful run, new bit improvements were implemented. The two subsequent runs completed their sections, enabling the operator to drill with one bit through what was previously a multiple-bit section. Rates of penetration were improved significantly over previous impregnated and roller cone runs. Requirements for down hole drive tools and bit trips were eliminated as was the risk of bit junk being left in hole.

This paper outlines the process that led to improved understanding of the formation drill ability, the research and development behind this new bit technology, the continuous optimization of the specific bit, its field performance, and the resulting cost saving for the operator.