bluuebunny/crossref_metadata_2025 huggingface dataset:
Geochemical Correlation and Migration Studies of the South Eastern Part of Tunisia
Authors: Rezouga Nawel , Mohamed Anis Belhaj , Saidi Moncef , Bouazizi Ibrahim
Published: February 2012

Several wells have been drilled in the south eastern side of Tunisia but only two wells are producing. However, to better understand the petroleum system mechanism of the area, a geochemical study was performed including oil-oil and oil-source rock correlation that was proved to be an essential tool for assessing oils occurrence, source rocks characteristics, their depositional environments and their distributions. The geochemical study was followed by 1D basin modeling to better understand the petroleum system functioning of the area.

The geochemical survey is based on the analysis of a total of 214 cutting samples and 6 crude oil samples. In a first part, potential Silurian and Ordovician source rocks were analyzed by Rock Eval to characterize their petroleum potential. In the second part, DST oil samples are correlated to Silurian and Ordovician source rocks using biomarkers and light hydrocarbon fraction. Migration distances calculation was based on carbozoles and benzocarbozoles.

Rock Eval results show that Silurian Hot shales exhibit good petroleum potential with mature type II oil prone kerogen, while Ordovician Shales show poor to fair petroleum potential and contain bad preserved type II kerogen.

Geochemical correlations study proved that the Silurian Hot shales are the main source rock in the basin and excluded any contribution from the Ordovician shales.

Carbozoles and benzocarbozoles concentrations in the oils of the northern part of the area suggest close proximity to the source kitchen while oils from the southern part seem to be sourced by a kitchen located in Ghadames basin.

The 1D modeling indicates that oil and gas generation from the Silurian hot shales began in the Carboniferous at about 360 Ma and reaches the maximum generation phase in the Upper Jurassic at about 160 Ma. The Hercynian unconformity surface was the main drain of secondary migration in the basin.
Application of New Techniques for Characterization of an Eocene Carbonate Reservoir in the Gulf of Suez, Egypt
Authors: Van Steene Marie , Vallega Valentina , Shaaban Sahar , Ghadiry Sherif , Haddad Elie , Bassim Essam
Published: February 2012

A variety of recently developed techniques are available to improve carbonate rock characterization. This paper reviews the application of these techniques on an Eocene carbonate reservoir from the Gulf of Suez.

Spectroscopy data was a main driver of the formation evaluation. It allowed an accurate determination of clay, pyrite and siderite with a good match to core data, while the photoelectric factor could not be used because of high barite content in the mud. Magnesium from spectroscopy indicated small amounts of dolomite were present.

Since rock texture has a strong impact on porosity and permeability in carbonates, texture-sensitive tools must be included in the evaluation. Based on nuclear magnetic resonance (NMR) data, porosity partitioning analysis showed that the porosity is dominated by micro and meso pore sizes. While the default correlations used for NMR in carbonates considerably overestimate permeability, a modified SDR equation was applied to predict permeability more accurately, providing a good match to core data.

Hydrocarbon properties have been found to vary vertically. NMR fluid identification stations were used to characterize the variation, which was validated by the drillstem test (DST) results.

Tar was identified based on the comparison of total porosity and NMR porosity. This is an important parameter as tar can affect the reservoir producibility.

Fracture analysis was performed on a data set of microresistivity image and sonic Stoneley data. The analysis performed on the Oil-Base MicroImager (OBMI) identified the orientation of the fracture system. The Stoneley wave processing determined that the majority of the fractures encountered in the reservoir were healed. This conclusion was supported by the core analysis results.

The work presented in this paper demonstrates how integrating the measurements from various tools and sources provides a good understanding of reservoir producibility in carbonates. The integrated evaluation was validated with core and well test results.
New State-of-the-Art Asset-Optimization Data Applications for Intelligent Completions in Digital Oilfields
Authors: Allen Clifford , Smith Robert
Published: February 2012

Information provided using intelligent completions in digital oil fields is increasing in importance, as it has the capability of minimizing the needs for custom data-gathering solutions as well as simplifying industry-data interfacing standards for multiple devices and systems. For assets using intelligent completions, solutions offered are attained by a combination of subsurface and surface or subsea sensors provided by several vendors.

Challenges arise when attempting to manage the interfaces required for providing real-time data from all points of interest (i.e., subsurface choke positions, flow, pressures and temperatures, wellhead positions, subsea facility readings, etc.).

This paper describes the design and implementation of an integrated data-applications system that can integrate data from multiple workflow sources for the purpose of maximizing field performance. The asset optimization applications acquire operating parameters from all points of interest, making them available to software modules designed to estimate key well-performance indicators.

The asset-optimization application discussed here is an integrated system that performs the following five services. A data-interfacing methodology acquires data from multiple sources or directly from down-hole devices. The integration service converts the subsurface and surface data to engineering units of measured well parameters. The well performance service uses well PVT and device-integration service values to execute complex calculations, like virtual flow metering, water-cut estimates, etc. The human/machine/interface service provides visualization, trending, and querying. The connectivity service facilitates structured data transfer to field historians.

The paper will explain how the system works and its implementation into fields of different scales and types to reduce information technology (IT) customization, simplify interfacing of multiple devices or systems, and accommodate evolutions in IT. Additional system benefits that included more efficient management of real-time data security, quality, redundancy, and mirroring will also be provided.
Proper Selection of Upscaling Techniques for Different Production Processes
Authors: Shehata Ahmed M. , El-Banbi Ahmed H. , Sayyouh M. Helmy
Published: February 2012

One main challenge in reservoir modeling is the computational costs of flow simulation. Although computer power has significantly increased in the past few decades, effective upscaling to reduce computation time in heterogeneous reservoirs still remains a challenge.

This research demonstrates the results of a comprehensive study on common upscaling techniques for porosity and permeability. This work aims at providing guidelines on which upscaling methods are superior for different depletion/production processes. The processes investigated include straight depletion, water injection, miscible and immiscible gas injection.

Several fine grid heterogeneous models were developed using actual field data and heterogeneity was evaluated using Lorenz and Dykstra Parsons Coefficients. Those different models were used to generate benchmark results for comparison with coarser models developed at different levels of coarsening and with different upscaling algorithms. Several scenarios were investigated in order to identify which upscaling algorithms result in the closest match with the fine model results. The results of coarse models were treated statistically to quantify their deviation from the fine models results and rank the upscaling algorithms accordingly. It was found that the depletion process affects the choice of the appropriate upscaling algorithm.

The coarse grid models lose some accuracy with increasing the upscaling ratio, as suspected. Also we found that several upscaling algorithms work equally well in depletion processes. However, only flow-based upscaling techniques (especially with open boundary condition) worked well for water injection processes. For miscible and immiscible gas injection processes, the use of flow based upscaling techniques is generally a must, while the flow-based upscaling technique with closed boundary conditions shows slightly better results than other flow-based upscaling techniques.

For miscible gas injection processes, in particular, the use of which upscaling technique is sensitive to the heterogeneity index as well specially for models with Lorenze Coefficient higher than 0.5.
Real Results of Optimizing Economics and Operations in a Workover Campaign in the Hassi Messaoud Field using Solid Expandables
Authors: Stringer Jordan A. , Saad Marc A.
Published: February 2012

Revitalizing aging fields can be complicated when viewed through an outlook of economic viability versus the associated operational and design risks. However, workover campaigns may be deemed more economically efficient and lower risk with the continuous advancements in technology, especially applicable to smart well designs. Workover projects are becoming ever more viable, with production being optimized through the application of advanced well construction products such as Solid Expandables along with existing brownfield infrastructure.

The operator of the Hassi Messaoud field, one of the largest and oldest onshore oil producing fields in Algeria, embarked on a large scale workover campaign to revitalize this field and optimize oil production from wells which have been drilled over 40 years ago. The typical workover program targeted extending the open-hole below the 7-in. casing across the Cambrian reservoir and completing the wells with a 4-1/2-in liner. Challenges with various formations encountered and the depleted reservoir resulted in the viability of only a slim hole configuration restricting production.

Maximizing the wellbore diameter across the reservoir while isolating higher pressured shale's directly above and balancing the economic return on investment required the inclusion of multiple technologies to achieve the well and production objectives, all using the existing well infrastructure.

A total of 7 wells have been worked over to date since early 2010 which avoided slim-bore configurations through the inclusion of 939m of 5-1/2" expandable tubular maximizing reservoir diameter and serving as a permanent mechanical barrier. The campaign also incorporated underbalanced drilling operations as a tool for mitigating subsequent pressured formations and testing production as required. The actual campaign had a reduction in operational time of 40% while significantly increasing and optimizing production rates.
Automatic Well Testing and PIP Calculations Using Smart Rod Pump Controllers
Authors: Ibrahim Ahmed Mohamed Fouad , Sadek Nael Nabil
Published: February 2012

Worldwide, as conventional oil resources are depleted, beam pumping system is becoming the most common type of artificial lift methods for onshore wells. Production testing of beam pumped wells is an important diagnostic tool to detect potential production problems and for monitoring reservoir performance. In addition, well test data and the Inflow Performance Relationship (IPR) combined with the production data help to design, analyze and optimize the whole well production system. With the growing number of beam pumped wells, the value of such data is increasing over time.

Published literature and field experience show that the traditional well testing methods for beam pumped wells have various limitations such as being hazardous, have a lot of assumptions, provide only a snapshot data and are costly processes. On the other hand, well testing is problematic if the wells are isolated or at a far distance from the field facilities. Also when large population of beam pumping wells are connected to central batteries, it is difficult to determine the daily production of each well or to identify the cause of low production in the battery, as there is not an easy way to identify which well is affected.

This paper will discuss a technology that started to replace traditional well testing facilities or at a minimum a new way to verify individual well performance on a day by day basis. The new method continuously infers the production and calculates the corresponding bottom-hole pressure using a smart rod pump controller system located at the well site by analyzing the downhole pump card data. The basic logical assumptions and methodology of the new method are summarized to give an understanding of how the test is implemented and under what conditions the test will be accurate. Real field data are shown and compared with data acquired by other traditional methods.
The Impact of Pore Geometry Aspects on Porosity-Permeability Relationship - A Critical Review to Evaluate NMR Estimated Permeability
Authors: Salah Ahmed
Published: February 2012

The permeability prediction is of extreme importance in hydrocarbon reservoir management. The reservoir rocks are made up of grains, cement and pore network. The pore network is made up of larger spaces, referred to as pores, which are connected by small spaces referred to as throats. The pore spaces control the amount of porosity, while the pore throats control the movement of fluids and the quantity of rock permeability.

The core analysis data for 219 sandstone and limestone samples were available. The data include porosity, permeability and capillary pressure by mercury injection. These samples represent 21 stratigraphic units. The geologic age varied between Cretaceous and Pliocene. Sandstone reservoirs are represented by 179 samples, while 40 samples represent carbonate reservoirs. The data were collected from different geographic areas within Egypt.

Pore-throat size distribution parameters were calculated from the data of capillary pressure. These data were used to approximate the distribution of pore volume accessible by throat of a given effective size. A new definition for micro-porosity was proposed based on pore throat size distribution. These data was used to descriminate the sample porosity into micro and macro porosity based on a pore throat cutoff, which was determined from the relationship between storage and flow capacity of the pore network. The relationship between permeability and aspects of pore geometry; micro-porosity, macro-porosity and pore throat parameters have been analyzed and discussed.

The interpretation of the results indicates that the permeability is mainly a function of pore-throat size distribution while the amount of the porosity or the porosity configuration is not the main factor that controls the amount of permeability. A new model for permeability prediction was develpoed which incorporate the pore space and pore throat. The obtained results have shown the great influence of pore throat on permeability prediction.
Advance Lifting Technology for Continuous Reservoir Monitoring and Production Optimization in Real Time – Aghar 04 Pilot Project Case Studies
Authors: Sabaa Ahmed , Crema Giordano , Soegiyono Rini
Published: February 2012

Permanent Downhole Gauges (PDG) can play great roles in production optimization as well as reservoir continuous monitoring and management. Data obtained from these gauges or sensors can give useful information to applications, including but not limited to monitoring artificial lift performance, pressure monitoring, transient well testing, and evaluation of well performance. Reservoir continuous monitoring, production losses mitigation, pump optimization and benefits from detection or prevention to early failure have been considered overcoming short-term concerns about cost containment during economic downturn.

This paper presents case studies based on a pilot project deployed by Agiba Petroleum Company and Schlumberger in Aghar-4 field, Western Desert, Egypt. This field consists of three producers that are equipped with permanent downhole gauge and integrated real time system connecting bottom hole sensor technology to some essential surface measurement capability.

Aghar-4 is a promising heavy oil field with a total of 13 wells drilled and being produced by sucker rod pumping to the date of the study. Aghar 4-1 was commissioned in January 2009 and is the first well in the Middle East operating with the intelligent downhole monitoring system application. This success story in Aghar 4-1 implied the installation of two more systems in Aghar 4-4 and Aghar 4-12. Later in October 2009, Aghar 4-12 made its history as the first world sucker rod well integrating downhole sensor, surface controller, and real time PC web-based satellite transmitted interface monitoring system.

Artificial lift downhole equipment failures often occur within a relatively short period causing reduced or deferred production. Continuous real time monitoring of the environment in and around pumps will significantly improve production through a proactive surveillance and optimization of artificial lift operations.
How to Measure the Correlation between Return of Oil Production Projects Realistically?
Authors: Costa Lima G. A. , Gaspar Ravagnani A. T. , Schiozer D. J.
Published: February 2012

The use of portfolio theory has been appointed as an important tool for economic risk management in the O&G industry. There are only 3 input parameters: (a) mean return; (b) standard deviation of return; (c) correlation between pairs of assets, projects, prospects, etc. Although simple, one practical problem with the application of this model is the estimation of correlation because there is no historical data as in the case of financial assets.

This paper presents a methodology for the estimation of linear and rank correlation between E&P oil and gas projects through the following steps: 1) Estimate the mean and risk of each project; 2) Identify the variables that are common to two projects such as oil price, fiscal regime, etc; 3) Simulate the return of each project; 4) Estimate the correlation between projects.

This model is applied to estimate the mean and risk of a portfolio of 3 projects typical from the deep-water in Brazil with reserves of 346, 629 and 694 million barrels. The fiscal model is based on Tax & Royalty. For all these projects, production strategy and production curve come from reservoir simulation.

Alternatively, correlation between return of projects is assumed subjectively (a typical number is 70%) but with this model it can be estimated in a much more sound way. Results indicate that main determinants of correlation are fixed cost, variable cost and oil quality. With this information, managers are able to select best portfolios – for example, by means of farm-in and farm-out – in order to create value for stakeholders considering not only means, but also risk and possible benefits from diversification.
Synchronization of Coiled Tubing Drilling (CTD) in Extended Reach Drilling (ERD)
Authors: Alimuddin Sultan , Shah Nihar , Das Abhirup , Kumar Neeraj , Pandey Ankit , Abhishek Kumar
Published: February 2012

Coiled tubing is used for a range of oil and gas well operations. It is mainly used in drilling, work over, pumping, logging etc. This technology is becoming an economic substitute to conventional drilling as it is highly cost and time saving. Drilling with Coiled tubing allows incessant supply of the pipe into the hole without constant interruptions, whether it can be as a drill string or tubing. Nowadays, most of the wells drilled are deviated because oil & gas reservoirs can be exploited more efficiently through extended horizontal wells. Also, Extended reach drilling make economic as well as environmental sense by reaching different pockets without drilling lots of wells. Through ERD we can also construct multiple wells to drain a large area from a single surface location. Moreover, the reserve situated in a populated area and geographically harsh area can be thoroughly exploited using high angle extended reach deviated and horizontal well.

However in drilling high angle deviated and horizontal wells with coiled tubing, the motion of coiled tubing drilling is somehow restricted due to generation of high friction forces which lead to buckling inside the well. Another challenge using CTD for ERD is effective transport of drilled cuttings, as the complete string is in sliding mode while drilling. Apart from this there many challenges which drilling industry is facing in CTD usage with ERD.

The main aim of this paper is to synchronize CTD usage with ERDs. Here we have presented the benefits & challenges of CTD-ERD system which can be used to save time and cost as well as proposing the possible current solutions. Knowing the limits and appropriate usage of coiled tubing in ERDs will save lot of costs and has potential to revolutionize the existing drilling activity of whole exploration, production and geothermal sectors.
A New Transformation for the Rapid Solution of the Rachford-Rice Equation in Phase Split Calculations
Authors: Gaganis Vassilis , Varotsis Nikos
Published: February 2012

The Rachford-Rice equation needs to be solved during phase split calculations required in several petroleum engineering applications such as reservoir simulation, determination of minimum miscible pressure, pipeline flow, etc. This calculation often has to be repeated for every discretization block and for every time step, thus claiming a significant fraction of the total computation time (CPU). Existing techniques exhibit a fairly poor performance when a bubble of a very light composition or a droplet of a very heavy one is present in the mixture. As the computation time in parallel computing implementations is determined by the slowest grid block calculation, this latency bears a huge impact on the total required CPU time.

In this work, a transformation of the conventional Rachford-Rice function is proposed with which the original equation is rewritten as a function of a single hyperbolic term instead of the vapor fraction. The transformed function is monotonic and strictly concave and can be fitted by low order rational model functions. A novel algorithm, which is able to fit such rational model functions and does not require the calculation of a derivative, is proposed instead of the Newton-Raphson straight line. The root of these functions is obtained directly by performing simple computations and is utilized as the next estimation.

The proposed method converges rapidly, as it requires only a single function evaluation at each iteration even in the case of negative flash or near-critical calculations. Every single estimate lies within the valid vapor fraction range thus ensuring robustness without the need for utilizing bracketing. Several test cases demonstrate an excellent performance compared to the existing methods hence leading to a robust solution and substantial CPU time savings.
A New Emulsified Acid to Stimulate Deep Wells In Carbonate Reservoirs: Coreflood and Acid Reaction Studies
Authors: Sayed M. A. , Nasr-El-Din H. A. , Zhou J.. , Zhang L.. , Holt S..
Published: February 2012

Acid treatments in high temperature deep wells drilled in carbonate reservoirs represent a challenge to the oil industry. The high temperature of deep wells requires a special formulation of emulsified acid that can be stable and effective at such high temperatures. At these high temperatures, both the reaction rate between acid and rock, and corrosion rate of tubulars are high. This fact makes protection of tubulars and reducing the reaction rate between rock and acid challenging.

A new emulsifier was used to prepare emulsified acids that can be used in stimulating deep wells drilled in carbonate reservoirs. All emulsified acid systems were formulated at 0.7 acid volume fraction, and the final HCl concentration was 15 wt%. A coreflood study was conducted in order to study the efficiency of the new emulsified acid to create wormholes, and to increase the efficiency of the stimulation treatment. Both low and high permeability Indiana limestone cores were used in the present study. The effect of acid injection rate, rock permeability, and emulsifier concentration on the performance of emulsified acid systems were studied. The reaction between emulsified acid and limestone rocks was studied using a rotating disk apparatus at 230 ºF, and rotational speeds up to 1,500 rpm.

The results showed, for both low and high permeability Indiana limestone cores, the new emulsified acid system created deep wormholes at all injection rates (0.5 to 10 cm3/min), with no face dissolution encountered during acid injection. The reaction rate between the new emulsified acid and limestone cores was measured using a rotating disk at 230 ºF. The dissolution rate increased as the rotational speed increased, indicating that reaction between emulsified acid and limestone is a mass transfer limited reaction. Both reaction rate and diffusion rate decreased as the emulsifier concentration increased from 0.5 to 2.0 vol%. From these results, the new emulsifier can be used in formulating emulsified acid systems that can be used effectively in stimulation of high temperature deep wells. This paper summarizes the results of testing the new emulsified system, and recommends its use for field application in deep carbonate reservoirs.
Evaluating the Severity of Dents in Pipelines
Authors: Popineau D.. , Wiet P..
Published: February 2012

Some years ago, after several pipeline accidents, the oil industry invited work groups to investigate the subject of predicting the burst pressures of damaged pipelines. Several damage evaluation guidelines were produced as a result, but these remained conservative in approach and, above all, were applicable only to minor damage.

Total, however, having observed far more serious damages on offshore pipelines, wished to go further and, in 2006, initiated a specific study as part of the "Deep Offshore Development", internal R&D project.

This cross-functional work permitted in 2011 the realisation of a finite element analysis model, EMPREINTE. This application has three objectives: to model pipeline dents, calculate the pipeline ultimate burst resistance and deduce a working pressure that includes an appropriate safety factor.

To evaluate damage to pipelines, this application uses an innovative approach: from the measured damage, it recreates the shape of the object that produced the observed dent, then simulates the damage by calculation and finally predicts the rupture pressure.

The method was validated by a series of burst tests on pipes on which dent-type damage (some extending to more than 50% of the pipeline diameter) had been inflicted and metal loss deliberately induced.

The software application was used in real conditions for the first time when an explosion damaged an HP gas pipeline feeding an LNG plant. Where strict application of the damage evaluation codes dictated the conservative course of replacing the damaged section, EMPREINTE confirmed that the repair could be postponed. The plant's production was therefore quickly resumed, minimizing LNG production losses (which might have attained several millions of USD if the damaged section had been replaced immediately).
Flow Structure Development Due to Injection Water into the Annulus of Heavy Oil Pipe Flow
Authors: Sakr Ahmed L. , Sultan G. I. , Safan M. G. , Tolba M. M.
Published: February 2012

This work investigates the flow structure development due to injecting water into the annulus of heavy oil pipe flow. Numerical simulation of the axisymmetric core annular turbulent flow is carried out using the standard k–ω model. The flow field and flow characteristics are investigated using FLUENT 6.3.26. The core annular flow of heavy oils-water in 15.24 cm diameter pipe, with three core diameters is considered. The influence of flow parameters upon the development of axial and radial velocity, turbulent kinetic energy, turbulent intensity, and strain rate profiles are investigated.

Results show that flow development depends on the core to outer diameters ratio, oil viscosity, flow velocity, and water loading ratio. As oil's viscosity increases, flow structure develops faster towards fully developed one. Fully developed velocity profiles show uniform distribution in oil's core, while all velocity changes occur in water flowing in pipe annulus. The flow in the core region seems to be as rigid body carried by annular water flow. It has been demonstrated that major changes in flow structure occur at the oil-water interface.
A New Approach Formation Tester Interval Pressure Transient Test Design
Authors: Tellapaneni Prasanna K , Shukla Sourabh , Jackson Richard R , Dixit Harshad
Published: February 2012

Increased deepwater drilling today requires that expensive and risky drillstem testing operations be optimized by other technologies that provide dynamic information about the formations to be tested. Wireline-conveyed interval pressure transient tests (IPTTs) are becoming a common practise today for optimizing and designing these expensive tests.

Typically, prior to an IPTT, there is only a limited amount of information available about the reservoir and fluids properties and it tends to be generally probabilistic. Therefore, the optimal design of IPTT tests is a necessary challenge for a successful and reliable test. IPTT is found to be dependent on the noise and on observable flow regimes associated with the pressure buildups. Success and reliability are not only a function of gauge metrology but also of the formation deliverability and geometry.

This paper describes a new methodology for IPTT design that allows estimation of the reliability of these transient tests. A normally distributed random noise is superimposed on the analytical pressure profile computed for a given formation, fluid PVT properties, and gauge metrology. The success of an IPTT in a particular environment is estimated based on the theoretical pressure derivative and noise-superimposed pressure derivative. This approach is repeated for a range of rock, and fluid properties and practical limits to identify what is a successful. Two field examples are presented to validate this methodology.
Study of Residual Oil in Tahe 4th Block Karstic/Fractured Heavy Oil Reservoir
Authors: Zhongchun Liu , Jirui Hou , Jianglong Li , Qian Cheng
Published: February 2012

Tahe 4th block karstic/fractured Heavy Oil Reservoir is a block bottom water reservoir with the greater heterogeneity. By the end of 2009, the yearly rate oil production is 7.23×106tons, and the oil recovery efficiency is 11.4%. But after a long period of development, many deficiencies of fast producing are exposed gradually: the water breaks through early in the oil wells, the water cut increase fast; the natural decline rate is high, and the development degree of the reservoir is lower.

By physical simulation experiments, the residual oil types and their effect factors have been investigated. The five main residual oil types in karstic/fractured reservoir have been determined. Furthermore, according to the dynamic and static information of wells, the production wells have been divided into three types by clustering method. And the 4th block of Tahe oil field have been divided into three zones in accordance with the well types, including a zone with a lot of caves, a zone with caves and fractures and a zone with fractures. Meanwhile, the main residual oil types and the research direction of EOR technologies in different zones have been pointed out.

The knowledge gained from this study can be a foundation to increase the well controllability and improve oil recovery in fractured/karstic carbonate reservoirs.
Design and Application of Drilling Fluids for HPHT Well - A Case Study of Mafia Field
Authors: Oriji A. B. , Dosunmu A..
Published: February 2012

It is very important to design a stable mud system for any detailed drilling programs. Application of the best practices and well planned engineering field execution is critical in drilling and completing HPHT wells in a cost effective manner and minimal operational problems. Conventional mud designs and test equipment fell short of addressing the inherent problems associated with HPHT wells. In this study, the conventional practices in mud design were reviewed and advances in design for best practices developed for Mafia field. Many of the conventional practices were actually found to be inadequate for HPHT drilling. This paper present techniques on determining and applying mud properties at HPHT deep wells through a rigorous laboratory test and mathematical equations to generate detailed engineering guidelines for HPHT drilling fluid. Water based mud were formulated with special additives at temperature between 250-500°F and 5,000-10,000 psi to check for its stability under such elevated temperature and pressure. A standard temperature concept used for controlling the surface mud weight was defined. With the actual field results from the Mafia field, model equations were developed and the sensitivity analysis done to show the relative influence of pressure and temperature on the drilling fluids using the spider and tornado plots. The model equations derived from the multiple regression analysis were used to predict and rank the best rheological properties for the field, thereby saving the time and rigors associated with laboratory experiments.
Fracture Network Parameters in Dynamic Models of Fractured Reservoir and Its Upscaling
Authors: Sohooli Kh..
Published: February 2012

Upscaling is often applied to generate practical simulation models from highly detailed geocellular descriptions. Upscaling of reservoir properties is critical to translate parameters measured from laboratory samples into values representative of the much larger grid blocks used in field simulators.

In this paper an upscaling methodology for naturally fractured reservoir simulation is developed and the effect of dominant forces on upscaling parameters is considered. Dominant forces which affect the fluid flow in naturally fractured reservoir are capillary force, gravity force and viscosity force. According to force dominancy, three different scenarios are proposed. In each scenario synthetic fine grid model represents actual fracture distribution. And upscaling parameters of each equivalent dual medium model are determined by matching the results of the fine grid model simulation.

In the first scenario viscose force is dominant. After running simulations the results of single porosity and dual permeability models are perfectly matched. So there is no need to tune the dual permeability model. In the second scenario in which capillary force is dominant, dual permeability and single porosity models showgood match. The results could be improved by tuning fracture porosity, fracture permeability and shape factor. Fracture porosity reduction and permeability reduction increases the pressure and water breakthrough time while decreases the oil production. In the third scenario in which gravity force is dominant the matching parameter is fracture porosity. Reduction of fracture porosity increases pressure and water cut while decreases oil and gas production.

To investigate the accuracy of the upscaling method, following validity tests are implemented; flow rate test, well location, saturation function, viscosity ratio and block height.

Comparing the results show that in this reservoir, dual permeability model matched better with the fine grid model than dual porosity model.
Deepwater Drilling in Both Hard and Abrasive Formations: The Continuing Challenge of Bit Optimization
Authors: Murphy Dominic , Mackay Donald , Gilmour James , Tetley Nicholas , Centala Prabhakaran , Iwere Edward , Bits Smith
Published: February 2012

Discovery of the Jubilee field, offshore West Africa presented a new challenge to the drilling industry when it had to contend with hard sandstone drilling in a deepwater environment. A solution to the key 12¼" section was developed utilizing a 4D modeling system, which accelerated optimization in the large hole section. This resulted in one bottom hole assembly (BHA) run to total depth (TD), compared with an average of four BHA runs previously. Additional modeling achieved a doubling of rate of penetration (ROP).

Further improvement to the one-run success would involve risk, and engineers had to weigh the prospective gain against the potential loss. In deepwater, particularly with a successful solution in place, high operating costs generally reduce the motivation to embrace change even if a potential cost-reducing solution could produce a significant economic impact. Achieving additional gains required an engineered approach to reduce the risks of deploying new solutions.

During the initial campaign the simulation models were constructed around standard rock types. However, the acquisition of reservoir core allowed direct testing on actual formation. This valuable new information became the basis for a new 12¼" PDC bit design and provided the justification for field testing. Additionally, different well plans called for a more challenging 17½" hole section on a new development. To solve the challenge, the operator considered using a different bit type and/or smaller hole size. Based on simulation results, and an analysis of global offset data of both sizes, the smaller hole size option was selected.

The initiatives have been extremely successful, culminating in two wells drilled in record time, with one of them reducing drilling time by 40%. This work has demonstrated that continuous improvement is possible, but where the cost of failure is high, a thorough engineering analysis is required to justify each change.
Promising Approaches to Enhance SAGD Performance in Uneconomical Tar-Sands
Authors: Akhondzadeh H.. , Fattahi A.. , Zare A. R. , Derahman M. N. , Idriss A. K.
Published: February 2012

Low permeability, shale barriers and low thickness are the main issues making significant portion of the immense heavy oil and bitumen resource uneconomical to produce. Two main troublesome cases were investigated in this study to address by applying appropriate solutions in SAGD process; firstly reservoirs with shale barriers and low permeability and secondly thin reservoirs.

In cases of low vertical permeability due to shale inclusion in the reservoirs, the effect of induced vertical fracture resulted in faster upward steam chamber expansion and increased oil recovery rate. Sensitivity analysis showed higher well spacing is beneficial to the process while applying the induced vertical fracture. In thin reservoirs, steam chamber reaches overburden faster and increases cumulative steam-oil ratio (cSOR), hence making recovery processes uneconomical. Appropriate placement of Induced Horizontal-Fractures (IHF) and off-set vertical wells with the later being in halfway of two adjacent horizontal well pairs in SAGD and acting as a steam injector was applied. The results showed such applications reduce cSOR.

Found from the sensitivity analysis, Induced Horizontal-Fractures positioned in the injector and the producer place improves oil recovery in thin reservoirs. When applying the fracture just in producer location, the oil recovery result is superior to the former case. In fact, IHF provide a path facilitating the oil drainage to producer that leads to faster oil transportation. The Off-set vertical well in the thin reservoir sweeps a part of the reservoir located beyond the chamber edges of two adjacent well pairs, hence reducing recovery time and cSOR. Based on sensitivity analysis, the most promising result of the process is achieved when initiating steam injection in the vertical injector from the beginning of the process.
Shale Gas Feasibility in Lacustrine Basin, Neem - Azraq Area, Muglad Basin, SUDAN
Authors: Ibrahim Maimona Mohamed
Published: February 2012

Is shale gas feasible in lacustrine basins?

Shale gas has become an increasingly more important source of natural gas in the United States over the past decades. Less attention given to shale gas in lacustrine basins and the few cases are not encouraging.

Abu Gabra formation act as the main effective source rock and reservoir in the same time gross thickness reach to about 7000m at the depocenter and characterized by the interbedded sands which producing condensate, light oil and recently considerable volumes of associated and dry gas.

Geochemical evaluation carried to evaluate the source rock, pyrolysis analysis results of 617 geochemical rock samples from Azraq wells and 337 geochemical rock samples from Neem wells, used to evaluate the richness of source rock (TOC), kerogen type (HI, S2) and thermal maturity (Tmax). VRo readings of 119 rock samples from Azraq wells and 73 geochemical rock samples from Neem wells used to measure the thermal maturity. 1D modeling done to predict the geothermal history and heat flow of the study area. The geomechanical characteristics of the source rock (brittleness) evaluated using the mineral and metal analysis result of 3 core samples from selected wells.

Based on the main key parameters used to evaluate shale gas in Marine basins there is high feasibility of shale gas in Lacustrine basin, where the average TOC in the study area (2.0 wt% - 3.0 wt%), VRo (0.48 C"" 1.0 to penetrated intervals) high heat flow (peak in tertiary 83 mw/m2).

High challenge of; litho-facies variation within short distance (difficulty of detecting sweet spot), suppression of thermal maturity, technological challenge of fracturing tools stands there to answer whether it will be success and economical viable?..
Orbital Forcing and Milankovitch Cyclicity Constraint During Permian Deposition on the Northern Margin of Africa, Southern Tunisia
Authors: Soua Mohamed
Published: February 2012

Rhythmic bedding forms one of the most characteristic features of the Late Permian in southern Tunisia. For almost a century, these bedding cycles have been interpreted to be only a part of reefal complex structure. These bedding cycles have been also identified in several neighboring wells, as well as in Libyan Jeffara, with different depositional environmental settings, interpreted as a climate variations controlled by cyclic variations in the Earth's orbit. A great variety of bedding cycles, from centimeter to meter-scale, have been described in outcrops and cores. However, exploration geophysical well logs are rarely used for this purpose, although these allow the study of thick successions of Middle-Late (either to early) Permian at decimeter-scale resolution and are widely available in the Jeffara Basin (Southern Tunisia). Therefore, a frequency analysis has been carried out of the Permian interval in well logs of four (04) available boreholes from the Jeffara basin sector. The interval contains cyclic intervals in most of the areas that underwent gradual subsidence during deposition of the Permian. In contrast, predominantly chaotic log responses are encountered in the Southwestern of the basin (northern limit of the Bou Nemcha-Telemzane complex high, BTC). Based on the calculated frequency spectra, a selection of logs showing pronounced cyclicity was made possible and used in order to identify the astronomical periodicity type represented in the sediments (i.e. eccentricity, obliquity or precession cycles). Alternatively, the Permian interval contains cycles which could be interpreted to represent 100 ky eccentricity and 40 ky obliquity Milankovitch cycles. A gradual decrease of cycle wavelength can be traced along the Roadian–Dzhulfian (and either Changhsingian) interval of several wells that probably reflects a regional decrease in primary carbonate production during this period. In this study the Permian system, in Tunisia, is revised for the first time as it is assigned to the international system nomenclature (standard chronostratigraphy). Using time series analysis, sedimentation rate and duration intervals have been also calculated.
Determination of Saturation Distributions in Water Displacement by Analytical Models
Authors: Haghighat S. Alireza , Mohaghegh Shahab D.
Published: February 2012

Water is injected in the hydrocarbon reservoir to serve two purposes, to maintain reservoir pressure and to displace oil as production proceeds in the reservoir.

In recent years, smart wells coupled with reservoir simulation models are used to improve the results of water injection performance. High frequency data (pressure, flow rate, etc.) that is a product of the smart wells provide the basis for a closed-loop, fast track updating of the dynamic reservoir models. While high frequency updating of the reservoir model remains a challenge, there are emerging technologies that can make such objectives achievable. An integrated approach that combines analytical and numerical solutions with artificial intelligence and data mining is proposed to ultimately achieve the closed-loop, fast track updating system. This study is the first step in that direction.

In this work the ability of analytical solutions to calculate reservoir water saturation profiles from field water cut data are investigated. Different flow regimes and reservoir geometries are considered during this study. Diffuse, segregated and capillary influenced flow models are analyzed in both one and two dimensional water injection using a commercial numerical simulator.

Different analytical formulations are applied for each flow regime in order to reproduce simulation production data. For each model a specific relative permeability relation is assigned and tuned with the aim of matching water breakthrough time and water cut history. An accurate match is achieved between water saturation profiles generated by the analytical models and the results by the reservoir simulator. The influence of simple reservoir heterogeneity on the robustness of the analytical models is studied.