bluuebunny/crossref_metadata_2025 huggingface dataset:
Finding Solutions to Sudoku Puzzles Using Human Intuitive Heuristics
Authors: Pillay Nelishia
Published: September 2015

Sudoku is a logical puzzle that has achieved international popularity. Given this, there have been a number of computer solvers developed for this puzzle. Various methods including genetic algorithms, simulated annealing, particle swarm optimization and harmony search have been evaluated for this purpose. The approach described in this paper combines human intuition and optimization to solve Sudoku problems. The main contribution of this paper is a set of heuristic moves, incorporating human expertise, to solve Sudoku puzzles. The paper investigates the use of genetic programming to optimize a space of programs composed of these heuristics moves, with the aim of evolving a program that can produce a solution to the Sudoku problem instance. Each program is a combination of randomly selected moves. The approach was tested on 1800 Sudoku puzzles of differing difficulty. The approach presented was able to solve all 1800 problems, with a majority of these problems being solved in under a second. For a majority of the puzzles evolution was not needed and random combinations of the moves created during the initial population produced solutions. For the more difficult problems at least one generation of evolution was needed to find a solution. Further analysis revealed that solution programs for the more difficult problems could be found by enumerating random combinations of the move operators, however at a cost of higher runtimes. The performance of the approach presented was found to be comparable to other methods used to solve Sudoku problems and in a number of cases produced better results.
A Review of Interoperability Standards in E-health and Imperatives for their Adoption in Africa
Authors: Adebesin Funmi , Foster Rosemary , Kotzé Paula , Van Greunen Darelle
Published: September 2015

The ability of healthcare information systems to share and exchange information (interoperate) is essential to facilitate the quality and effectiveness of healthcare services. Although standardization is considered key to addressing the fragmentation currently challenging the healthcare environment, e-health standardization can be difficult for many reasons, one of which is making sense of the e-health interoperability standards landscape. Specifically aimed at the African health informatics community, this paper aims to provide an overview of e-health interoperability and the significance of standardization in its achievement. We conducted a literature study of e-health standards, their development, and the degree of participation by African countries in the process. We also provide a review of a selection of prominent e-health interoperability standards that have been widely adopted especially by developed countries, look at some of the factors that affect their adoption in Africa, and provide an overview of ongoing global initiatives to address the identified barriers. Although the paper is specifically aimed at the African community, its findings would be equally applicable to many other developing countries.
The level of participation during the development of a mobile care data application for home-based healthcare in a developing context: An actor-network theory perspective
Authors: De la Harpe Retha
Published: September 2015

The context of this study is home-based healthcare in a South African resource-restricted community. The research case involved the design and development of a mobile care data application, created to assist community caregivers in their professional activities. The development principles of a suitable application for feature phones (limited functionality) in this context are not fully established, however. For the mobile care data application, a participatory design approach was employed. It was observed, conversely, that the level of participation of all stakeholders differed significantly. It was especially observed that the designer and end-users were less involved in the actual development of the prototype. These differences may have an influence on the end product/result. Actor-network theory may provide the mechanism to describe how the human and non-human actors formed relations as they participate in these processes. Considering the alignment of such networks, the coordination, devices and passages during the four translation moments provide valuable insights in the design and development of technology products. This paper will consider these elements in more depth. With a social embeddedness perspective the level of participation was high during the design of the proposed ICT solution with the active participation of the care givers from the developing context. The socio-economic factors of the developing context influenced the development of the mobile application with the complexities of the socio-technical context evident in the difficult translations between the participants
Fractures Relative Permeability and Capillary Pressure Curves - Effect on Thermal Recovery Processes of Heavy Oil Naturally Fractured Reservoirs
Authors: Ghedan Shawket G. , Kumar Anjani
Published: September 2015

It is common practice in modeling of naturally fractured reservoirs, NFRs, to neglect capillary pressure, Pc, and utilize straight line, zero to one, relative permeability, Kr, curves for the fracture network. More often than not, however, reservoir stresses and partial mineralization of fractures render fracture conductivity to remain relatively low for simultaneous ease of flow of two phases. Furthermore, fracture Kr is often found to be lowered by fractures’ tortuosity, and wall roughness. The objective of this study is to expand on the characterization of fractures Pc and Kr data and to determine its effect on the performance of heavy oil NFRs produced under thermal recovery processes.

According to the percolation model1, 2, fracture Kr curves approaches straight line form when gravity segregation forces dominate the capillary forces, producing larger fracture height dimensionless parameters. In heavy oil NFRs, however, smaller water-bitumen density differences coupled with smaller fractures apertures may lead to the need of using non-straight line, physical, Kr curves. This may be associated with non-zero Pc curves. The differences in heavy oil recovery performance, due to physical Pc and Kr curves, was established through Dual Porosity/Dual Permeability modeling of Steam Assisted Gravity Drainage, SAGD, thermal recovery process of a heavy oil NFR.

Fractures' heights and apertures, gas- and water-bitumen density differences, and interfacial tensions would either support the use of non-straight line, physical Kr curves or renders the use of straight line Kr curves to be acceptable. Large density differences between steam and heavy oil supports the use straight-line Kr curves for the gas-heavy oil system, while smaller water-heavy oil density differences supported the use of physical Kr curves for the water-bitumen (heavy oil) system.

Utilization of physical Kr curves revealed appreciable differences in the performance of SAGD process for smaller fracture apertures and relatively minor differences for larger fracture apertures. Straight-line Kr curves gives hot water more mobility in the fractures quickly expanding the steam chamber to contact more matrix rock and recovering more oil in the process. Physical Kr reduces the size of the steam chamber and in turn recovering less oil in the process. This paper presents the details of these results and tries to determine the effect of other reservoir parameters such as the fracture aperture, level fracture-matrix rock permeability contrast, and wettability of matrix rock on the process.

This paper adds value to the effort of proper modeling of thermal recovery processes of heavy oil NFRs through the use of more theoretically and experimentally backed fracture Pc and Kr input data. For some reservoirs, this may make or break certain thermal recovery processes, which may help to avoid wrong economic decisions for some projects.
Modelling Pipeline and Choke Optimization for Improved Gas Field Production using an Integrated Asset Model: A Case Study
Authors: Talabi O. A. , Nitura J. T. , Rodriguez N. J. , Fernandez M. , Choudhary M. K. , Johari S. F. , Hanifiah N. M. , Kumar Ashok
Published: September 2015

A case study modelling pipeline layout and asset-wide choke optimization in a dry gas field of multiple reservoirs is presented. The methodology utilized an integrated asset model (IAM) and lexicographic optimizer with a neural network accelerator to perform production optimization while considering system constraints on the quality of the produced gas blend as well as the effect of significant differences in reservoir pressure on total asset production. The field comprises several gas reservoirs; some are already developed and in production, and others are in development with more wells to be drilled and brought online later. Production from the different reservoir units is commingled as the units tie into a common surface production network. Based on preliminary simulation studies, the commingled pipeline causes production deferment due to backpressure. It was postulated that a dedicated, high-pressure pipeline would be required to mitigate this. The purpose of this study was to investigate if the cost of the dedicated pipeline could be avoided by selectively choking back high-pressure wells to allow lower-pressure wells to flow and assess the incremental recoverable volume is CO2 content in blended gas was optimized.

The first step of the pilot study was to create a representative surface network model that could be coupled to the available subsurface black oil simulation model for two of the fields. A model integration software platform was used for linking the surface to subsurface, and a representative simulation control strategy was input. A custom-built choke optimization logic using an optimizer that honors the CO2 constraints and maximizes gas production up to the asset sales gas plateau target was implemented and triggered every month during the simulation. The optimized simulation generates a gas rate and choke pressure drop schedule per month per well that then can be used to develop a monthly choke set-point schedule. The simulations were run for 12 years.

Based on the results, using choke optimization, the production deferment—cumulative production difference between dedicated pipeline and comingled pipeline—can be reduced by up to 80%, making the choke-optimized comingled pipeline case more economic than the equivalent dedicated pipeline case. In addition, cumulative production can be increased by approximately 34% in both dedicated and comingled pipelines while honoring the CO2 production constraint.

The results of this study demonstrate the potential benefits of choke optimization in the gas field to both increase production by better field management and offset the need for an expensive dedicated pipeline, allowing the field improve its production potential at minimal cost.
Optimization of Production in Slanted Horizontal Wells in Tight Reservoirs
Authors: Temizel Cenk , Purwar Suryansh , Abdullayev Azer , Urrutia Karelis
Published: September 2015

Economic production from tight-oil formations requires the same hydraulic fracturing techniques used during production of shale gas, and the same horizontal well technology is often used. Tight-oil formations are heterogeneous and greatly vary over relatively short distances. Thus, even in a single horizontal drilled hole, the amount recovered can vary, just as recovery within a field or even between adjacent wells can vary. This can make evaluation and decisions regarding profitability difficult. In relatively thinner pay zones, horizontal or slanted wells can be successful in terms of productivity as long as robust reservoir management is applied with well designs that consider both geology and operational control variables. Thus, it is crucial to understand every control and uncertainty parameter to help maximize efficiency and recovery within such systems.

Robust commercial optimization and uncertainty software is coupled with a full-physics commercial simulator that models this phenomenon to investigate the significance of major parameters on the performance of horizontal wells in tight-oil formations.

Slanted wells provide more flexibility and access to pays than vertical wells drilled from the same surface location, which is of more significance in tight formations because of less communication between zones. The results of the study not only confirm this, but also show the increased value provided using slanted wells compared to vertical wells in tight formations. The study also illustrates the significance of each optimization and uncertainty variable in terms of the success of recovery from slanted horizontal wells in tight formations.

The results and sensitivities are compared and discussed considering a comprehensive literature review of recycling gas-condensate reservoirs using different process optimization methods. The significance of all major parameters is outlined using tornado charts to serve as a practical example for optimization of similar future applications.
Compositional Subsurface-Surface Simulation of a Complex Miscible Acid Gas Injection System
Authors: Kathrada Muhammad
Published: September 2015

An integration study on a complex system of several sour oil and gas-condensate fields based in the south of Oman has been conducted. Sour components are removed from the sales gas stream with the resultant concentrated acid gas being reinjected into the reservoirs. Acid gas is highly miscible and improves ultimate recovery from the reservoir. Hence it is imperative to model the separation and injection of this acid gas accurately. The system is further complicated in that there are two surface plants with different reservoirs flowing into them leading to mixing of fluids. Tracking these fluids with time requires a completely integrated model. To this end subsurface reservoir simulation models, the pipeline production and injection networks and the surface facilities have been linked in a closed loop.

The objective of the model is for long term forecasting and development optimisation. It is also a useful diagnostic tool in debottlenecking the system and identifying areas of process improvement. Such large scale detailed complex integration studies can be very time consuming. Getting all the correct data from the respective stakeholders, overcoming software limitations, troubleshooting and optimizing various elements within the integrated model all make for an arduous task. The final result though is a model with all the working elements of the system that stakeholders can modify and interrogate on the whole to better plan and optimize the cluster development from both a sub-surface and surface perspective.
Detection of Bedding Corridors From Open-hole Logs in Vertical Wells and Their Impact on Geomechanical Assessment
Authors: Sirat Manhal , Noufal Abdelwahahb
Published: September 2015

Bedding corridors are sub-horizontal tabular bodies of bedding plane weak zones formed as shear swarms, which vertically divide the entire reservoir thickness and extend laterally as their layers. Bedding corridors are genetically related to shearing along the bedding planes and they contribute to the conductive systems in few Abu Dhabi reservoirs. They can be best identified from horizontal borehole image logs, and as spikes in open-hole logs. Natural bedding corridors can be considered as indicators of the reservoir stress history, where they form extraordinary clusters of a huge number of quasi-parallel shear fractures in a transpressional regime.

In many oil and gas reservoirs, natural bedding corridors networks help drain hydrocarbons and other fluids. The role of bedding corridors is particularly important in reservoirs having a tight matrix. In carbonate formations, for example, it is quite common to observe a permeability contrast of 1000mD or more between the rock matrix and surrounding bedding corridors. In this paper we differentiate between image-log porosity and density-neutron porosity, which is regarded as secondary porosity attributable to fractures. We also introduce here a working hypothesis about their effect on hydrofraccing being part of geomechanical assessment.

Results indicate that the horizontal stress anisotropy (Shmin/SHmax ratio) is the key parameter to predict bedding corridors behavior under different stress regimes. Swapping stresses with depth is common in Abu Dhabi fields, where a strike-slip regime can open and dilate the shear along the bedding planes. It is recommended to opt for horizontal wells hydrofraccing to maximize the intersection of those bedding corridors compared to vertical wells.

The significance of this approach is that once a diagnostic signature can be recognized in open-hole logs, in combination with lost circulation data, it can be used to locate bedding corridors in other vertical wells with no image logs. Geomechanically, these corridors can be used efficiently to increase production particularly in tight and unconventional reservoirs.
Experimental Study of Wettability Alteration during Nanofluid Enhanced Oil Recovery Process and Its Effect on Oil Recovery
Authors: Li Shidong , Genys Mindaugas , Wang Kun , Torsæter Ole
Published: September 2015

Nanoparticle was proposed as a new Enhanced Oil Recovery (EOR) agent for its great potential of increasing oil recovery and wettability alteration was suggested as one of main EOR mechanisms. We conducted a series of core flooding experiments with nanoparticles fluid (nanofluid) as tertiary recovery method. Core plugs injected by nanofluid were performed for Amott test to measure wettability index and showed the effect of nanofluid injection on wettability alteration. During core flooding experiment aged Berea sandstone cores were employed and pressure drop across core was measured, oil production rate was recorded as well. Hydrophilic silica nano-structure particles and hydrophilic silica colloidal nanoparticles with different concentration were utilized in above experiments. The objective of this experimental study is to investigate wettability change of core during nanofluid flooding process and its effect on oil recovery.

The results showed that injection of nanofluid can increase oil recovery, for some cases effect of nanofluid flooding on recovery is quite significate. Colloidal nanoparticles fluid injection didn't affect pressure drop obviously, while pressure drop increased significantly during nano-structure particles fluid flooding, which might be one of EOR mechanisms. Nanofluid flooding can change core to be more water wet and presence of crude oil can affect wettability alteration process by nanoparticles. However, increase of wettability index is independent of nanoparticles concentration.
Detailed Reservoir Characterization for Key Strategies of Unconventional Reservoir Development
Authors: Cui Esther
Published: September 2015

Unconventional resources play significant role with the increasing demand of hydrocarbon. Horizontal well drilling and multiple-stage hydraulic fracturing are the dominant technology required to achieve economical gas flow rates and improve gas recovery. The accurate prediction of well performance is a major challenge, which involves exploration and evaluation of gas reservoir, proper gas reservoir management, well spacing and hydraulic fractured well design, reservoir simulation and completion process, and reservoir specific issue. The identification and evaluation of tight gas reserves and proper production calculation is the priority. Integration of multi-discipline and multi-scale data is important for field development of unconventional reservoir as compared to the conventional reservoirs.
Integration of Microseismic Monitoring and Advanced Production Analysis: A Real Case Study for an Unconventional Reservoir
Authors: Turri F. , Sciortino M. , Brignoli M. , Mantica S. , Rotondi M.
Published: September 2015

The exploitation of unconventional reservoirs requires hydraulic fracturing treatments, aimed at enhancing reservoir rock permeability through the re-activation of existing natural micro-fractures and the generation of new fractures in the near-wellbore area. Microseismic Monitoring (MSM), which consists of acoustic recording of the induced fracturing events, has nowadays become a common approach for real-time tracking of the fracture network evolution.

The present work is based on the analysis of microseismic and production data coming from three multi-fractured wells drilled in a shale gas reservoir. Information derived from MSM is integrated with the Advanced Production Analysis (APA) results, to assess if the MSM interpretations are able to provide preliminary indications about the production behavior of the fractured wells before start-up. The spatial localization of microseismic events and their moment magnitude are derived from the interpretation of the seismic signals recorded by geophones during hydraulic fracturing. Data analysis, based on the cross-plot of the event moment magnitude versus the distance between the event and the nearest geophone, allows the determination of the spatial range bias, i.e. the effect for which the level of the recorded magnitudes depends on the distance from the geophones. A novel methodology was developed to correct the spatial range bias by combing a Gaussian function and the Gutenberg-Richter law for fitting the Frequency Magnitude Distribution. After the correction, microseismic data from different wells and frac stages can be directly compared and used for the evaluation of the Stimulation Efficiency (SE) and the Stimulated Reservoir Volume (SRV).

APA is used to analyze production data from the three selected wells in order to characterize both the fractured system and the reservoir.

Even if the results obtained from MSM and APA techniques are often at different scales and not quantitatively comparable, it is still possible to obtain useful information from their integration. APA confirms, indeed, the interference between wells production due to the overlap of different SRV, as initially estimated from MSM interpretation. Thus, the results of the developed methodology allow to improve well placement, stimulation operation design and field development strategies.
Well Placement Optimization Using Imperialist Competition Algorithm
Authors: Al Dossary Mohammad A. , Nasrabadi Hadi
Published: September 2015

Developing an efficient and optimized field development plan is a crucial and vital task that aims to increase the productivities as well as the recovery factors of oil and gas fields and hence increase the profitability in the most effective manner. In this paper, a novel algorithm has been applied for the first time in oil & gas industry to find the best optimum well location for maximum well productivity. The Imperialist Competitive Algorithm (ICA) is an evolutionary algorithm that mimics the social political imperialist competition. In this algorithm, an initial population that consists of colonies and imperialists are assigned to several empires. The empires then compete with each other and weak empires collapse and the powerful empires possess their colonies. The ICA performance was compared with the well-known Genetic Algorithm (GA) in three optimization scenarios: 1) a vertical well in a heterogeneous reservoir, 2) a vertical well in a channeled reservoir, and 3) a horizontal well in a channeled reservoir. In all three scenarios, it was observed that the ICA resulted in better solution compared to GA at a fixed number of simulation runs.
Mechanistic Modeling of Alkaline/Surfactant/Polymer Floods Based on the Geochemical Reactions for Snorre Reservoir
Authors: Khaledialidusti Rasoul , Kleppe Jon , Enayatpour Saeid
Published: September 2015

A considerable amount of oil resides in many reservoirs around the world such as the Snorre reservoir, a sandstone reservoir in the North Sea. The effect of lowsal waterflooding was explored in this field and the laboratory via Single Well Chemical Tracer (SWCT) and coreflood tests. Since the results showed that the amount of oil recovery after lowsal waterflooding was insignificant, the effect of alkaline/surfactant/polymer (ASP) flooding is investigated.

Mechanistic modeling of ASP injection is performed based on the geochemichal reactions such as aqueous, ion exchange, and precipitation/dissoloution using the reservoir properties. Due to lack of ASP flood of the laboratory corefloods for the Snorre reservoir, first, ASP coreflood is modeled based on the performed laboratory coreflood to validate the procedure of the mechanistic modeling of ASP. Second, the feasibility of ASP method for the Snorre oil field is investigated by a series of 1D coreflood simulations. Different strategies are designed to identify key parameters and an optimum design is determined based on the simulation results.

Since the propagation of alkali, in-situ surfactant (soap), and surfactant plays a vital role to succeed ASP method, mechanistic modeling of ASP flooding in the core is an effective tool to ensure the proper propagation to support low IFT and favorable salinity gradient. The results of different strategies demonstrate that alkali, surfactant, and polymer propagate simultaneously and in consequence, ASP flood can be feasible in the Snorre reservoir. The effect of the combination of low-salinity with ASP in order to provide optimum salinity for the soap/surfactant phase behavior is studied. The results also verify that the amount of oil recovery increases by injecting more slug size of chemicals; however, almost the same amount of oil is recoverable by injecting half or less of chemicals by designing the salinity gradient in the injected fluids. The effect of cation exchange reaction (CEC) is also investigated. The results show that the higher CEC leads to higher alkali consumption and it results in slower propagation of the alkali and pH front.

Mechanistic modeling of ASP is a highly sophisticated process due to the complicated ASP phase behavior and the geochemical reactions that happen in the reservoir. In this paper, all of the key parameters such as the chemical reactions, alkali consumption, soap generation, and the effect of the phase behavior are considered using the UTCHEM simulator. Geochemist’s Workbench® release 6.0 database is used to find the thermodynamic reaction equilibrium data for solution and solid species. The initial equilibrium concentrations of aqueous, solid, and adsorbed species are calculated using the EQBATCH program.
New Use and Interpretation of Production Logging Infractured Reservoir Wells with High Water Cut
Authors: Villasana Julio , Ham J. M. , Perez R. , Mehranfar R.
Published: September 2015

Production records provide important information about volumes and contribution areas in oil wells. Over time, the records are also a great contribution to monitoring of oil water contacts. In adition, with these records it is possible to test production pressure without surface wellhead’s measurements.

This new approach to obtain such information results from the need to determine the source of water in sime carbonate fields with channeling and / or coning problems, as well as to decide an optimum choke in the operation of the well.

For this reason we have implemented a new way of obtaining production records that allows us to maximize the use of data by analysis of applied engineering.
Maximizing Recovery by Integrating an Advanced Reservoir Simulation Approach into the Drilling Process of Horizontal Wells
Authors: Salim D. , Couto P. , Alves J. L. , Freitas E. , Haq S. , Denichou J. M.
Published: September 2015

The successful drilling of horizontal wells is extremely difficult, mainly due to lithological discontinuities and seismic uncertainties. To overcome such challenge, Well Placement technique is used to interactively position the well based on geological and seismic criteria together with LWD measurements. While covering drilling, geology and geophysics, most Well Placement approaches rarely consider reservoir engineering aspects. This paper presents an innovative methodology that integrates reservoir engineering into Well Placement workflow to improve well's productivity performance.

The applied method is based on advanced 3D modelling, where by means of numerical reservoir simulations, productivity predictions are performed not only on the planned well but also at the executed trajectory. To increase prediction accuracy, a refined gridding with variable cell size technique is applied to enhance pressure and saturation sensitivity. The level of precision is improved by using LWD measurements, such as most precise formation pressure, permeability near wellbore and remote boundary mapper technology that provides a detailed reservoir structure based on formation resistivity contrast.

This methodology was employed in a real case study of a horizontal well drilled in an offshore sandstone field in Brazil. As common occurrence in Well Placement operations, the executed trajectory had significant geometrical differences compared to the planned one. For both planned and executed wells, a detailed reservoir model was created using the inputs of LWD measurements. Numerical simulations were then applied to both wells in order to evaluate the impacts caused by the trajectory variations, showing the expected productivity results versus the actual ones obtained at the drilling operation. The results demonstrated indeed a major productivity impact in all reservoir fluids when a well trajectory is subjected to geometrical changes. However, only through the use of this integrated approach could such impact be quantified, since the traditional Well Placement methodology cannot determine the effects on the productivity response based only on the geological and petrophysical aspects.

The work delivers a novel ability to construct optimal horizontal wells not only by including conventional Well Placement technique, using geological and geophysical criteria, but also by introducing into the workflow an advanced numerical simulation approach. Such integration allows the operator to predict the impacts on the productivity as the trajectory is being changed, and the actual reservoir geometry and its properties are determined by LWD measurements.
Performance Evaluation of First Horizontal Well Implementation in Tight Carbonate Reservoir Yields Critical Results in Western Desert, Egypt
Authors: Salah Mohamed , Bereak Ahmed , Gabry M. A. , Gallab M.. , Fattah S. I.
Published: September 2015

Abu Roash-D (AR-D) is a common carbonate reservoir in Abu Gharadig (AG) field, Western Desert of Egypt. It is characterized as a limestone reservoir which has good lateral continuity, contains natural fractures with poor connectivity in addition to formation tightness. The heterogeneity and tightness of AR-D reservoir are the main challenges to maintain economical well productivity.

Initially, Several vertical wells had been drilled in AR-D reservoir and stimulated via matrix acidizing, but could not achieve or sustain the economical target production rates. Recently, two vertical wells were acid fractured as a trial to produce conductive fracture with sufficient length to allow more effective drainage around the wellbore, but test results showed higher flash production of 3,000 BOPD then rapid decline and low recovery occurred. This awesome results encourage embarking on field development and additional production data gathering for development optimization. The large interest in developing such low permeability reservoirs has been a direct result of the favorable economics achieved by the advancements in horizontal well drilling and stimulation technologies hold great promise to increase production by dramatically increasing the contact area with the producing interval, maximizing the drainage volume around a well and link those natural fractures network.

So, In order to economically develop AR-D reservoir resources a comprehensive parametric study was conducted on low permeability AR-D reservoir of western desert (through gathering of additional data during the development a major reservoir, the review of the core and test permeability data across the reservoir as well an evaluation of the uncertainties and associated development risks) has documented some critical results, showing the productivity index ratio between stimulated vertical and horizontal wells illustrates the improvement to be obtained from higher reservoir contact.

This paper takes a multidisciplinary approach to better understand how to enhance the productivity of low permeability AR-D reservoir in Western desert of Egypt through a detailed analysis of well performances and exploitation approaches after the successful Implementation of horizontal wells to maximize drainage volume around the well to revive low producing wells due to reservoir tightness and discuss the actual performance of the horizontal wells and compares them with the offset conventional vertical wells and highlights the productivity gain.
Pressure Drop Due to Multiphase Flow Using Four Artificial Intelligence Methods
Authors: Attia M.. , Abdulraheem A.. , Mahmoud M. A.
Published: September 2015

The evaluating of the pressure drop due to multiphase flow in vertical pipes and inclined pipes is crucial for oil and gas industry. Numerous correlations and models have been developed to calculate the pressure drop in vertical wells but the effectiveness of these models is still under debate. Most of the correlations and models were developed to calculate the pressure drop due to multiphase flow based on accurately and reliably measured flow parameters. However, they can work best within the proposed data ranges. Their accuracy degrades if they are used for data out of the measured ranges.

Artificial Intelligence (AI) has proven to be an alternative solution to many of the problems where physics and classic statistics fail to provide satisfactory solutions due to limiting assumptions and complicated reality. Different AI methods, viz., Fuzzy Logic (ANFIS), Neural Networks (ANN), Support Vector Machine (SVM), and Decision tree (DT) were used in predicting the multiphase flow pressure drop in surface pipeline and production tubing for oil fields. 239 published real field datasets were used in constructing the flow line model and about 795 datasets were used to construct the pressure drop from the well head pressure to the bottom hole flowing pressure (tubing model).

The models were tested by dividing the data into three categories:, (60%) were used for training and (15%) for validation, and (25%) for testing. The results of testing showed that ANN, ANFIS, and SVM give better predictions than the common correlations in case of pressure drop from the wellhead to the GOSP (flow line) or from the wellhead to the bottom hole location (tubing). The average absolute percentage error (AAPE) was 1.15% for ANN, 0.39% for ANFIS, and 9% for SVM, and 77% for DT for the flow line model and the error was 3.8% for ANN, 4.5% for ANFIS, 4.3% for SVM, and 3% for DT for the tubing model.
Experimental Investigation of Alkaline/Surfactant/Polymer (ASP) Flooding in Low Permeability Heterogeneous Carbonate Reservoirs
Authors: Shedid Shedid A.
Published: September 2015

Carbonate reservoirs have been recognized as very heterogeneous formations due to complex depositional environments, which complicate application of Alkaline/ Surfactant/Polymer (ASP) process.

The main objectives of this study are to (1) present progress of screening criteria for chemical EOR processes, (2) investigate the feasibility of Polymer flood (P), Alkaline/Polymer (AP), Surfactant/Polymer (SP), and Alkaline/Surfactant/Polymer(ASP) processes in low permeability carbonate reservoirs, (3) study the effect of using high concentration of surfactant in the ASP slug on oil viscosity and attained recovery, and (4) study the effect of initial oil saturation at the start of the ASP process on the oil recovery. Actual crude oil, formation brine, and low permeability carbonate reservoir samples are used to undertake this experimental study. Viscosity, pH, and Interfacial tension (IFT) for oil-water, and different chemical systems are measured. Additionally, eight core flood experiments are carried out to test different formulated chemical slug volumes and concentrations on oil recovery.

The results indicated real progress in screening criteria of polymer EOR processes and thier successful applications in lower permeability reservoir (> 10 md). This study proved that ASP process is successfully applied as an enhanced oil recovery in carbonate reservoir having permeability less than 5 millidarcy (md). Moreover, addition of sodium hydroxide (NaOH), or surfactant (F75N) in polymer constituting a single slug has important effects on viscosity and pH of the different chemical slugs applied.

The results also pointed out that the application of ASP process at higher mobile oil saturation leads to higher oil recovery than when applied at later stages of water flooded low permeability carbonate reservoirs. In addition, Alkaline/ Surfactant/Polymer (ASP) process has successfully recovered the highest recovery in comparison to other chemical processes. The application of the attained results develops a new window for more applications of chemical EOR processes in lower permeability carbonate reservoirs.
Innovative PDC Drill-Bit Cutter Technology Leads to Performance Improvements in Western Desert, Egypt
Authors: Ismail Ahmed , Stockey David , DiGiovanni DiGiovanni , DiGiovanni Anthony , Burch Connie , El-Moniem Mohamed Abd , El-Desouky Waleed , El-Sawy Ahmed , Galal Mohamed
Published: September 2015

The ongoing drilling campaign for an operator drilling in Egypt's Western desert area involved drilling vertical and directional wells approximately 5,000- to 5,500-m deep. The application involved drilling through very hard and abrasive sandstones, and intercalations of shale, sand, silt and dense dolomite inter-beds of about 25,000 psi unconfined compressive strength (UCS). Historically, poly crystalline diamond compact (PDC) drill-bit showed inconsistent bit performance that included premature bit failure and low rate of penetration (ROP), resulting in costly bit trips to the surface.

New and improved bit technology was required to improve the penetration rate and footage to reduce bit trips to the surface and improve the overall drilling performance. An in-depth study of the formation properties, wireline logs, drilling parameters and bit dull analysis was performed. Detailed analysis identified this application can benefit from running cutters with a non- planar cutting face on a field-proven seven- blade PDC bit frame. The bit was run on a Rotary Steerable System (RSS) coupled with a positive displacement motor (PDM) on top of the BHA to further improve the drilling efficiency and overcome any challenges.

Upon deployment, the 8½-in bit design with the new 16-mm cutters with non-planar cutting structure combined with optimized depth-of-cut control, stability, hydraulics efficiency and balling prevention features led to improved performance when drilling the complex, hook-shaped well profile (where torque and drag were an issue in the past). Compared to field offsets, the bit drilled very smoothly and aided the operator in placing the well in the correct direction with minimum bit- torque caused from bit and formation interaction. Offset bits fail to achieve the required directional plan in the past because of the severe nature of drilling in the area.

This integrated solution resulted in a 15% improvement in the ROP as compared to the offsets and a 57% improvement in footage drilled. This performance replaced six drill bits, which were used to drill the same interval in the offset wells. The new innovative PDC cutter technology saved the operator at least USD 250,000 from the planned authority for expenditure (AFE) cost, as well as set two consecutive footage records. This paper outlines the problems in drilling this challenging area, the thought process behind using the various technologies incorporated in the PDC bit design and the keys to overall success.
Borehole Stability and Field Stress Analysis with Azimuthal Logging-while-Drilling Technology: A Case History
Authors: Azim Shaikh Abdul , Chowdhuri Sankar , Sahib Mohammad Raffi , Mohammad Tarek Abdel , Abdulkarim Anar , Samie Mohamed , Aki Ahmet
Published: September 2015

Real-time azimuthal acoustic measurements were introduced recently in the logging-while-drilling (LWD) industry. For the first time, this technology was used as part of the bottomhole assembly (BHA) to acquire information related to principal stress orientations in the deltaic to marine Zubair clastic sequence of onshore Kuwait.

A deviated 8.5-in. hole section of the well was planned through sand-shale sublayers with a borehole inclination ranging from 46 to 88°. This section is characterized by time sensitive borehole deterioration and significant variations in pore pressure. These factors result in severe hole instability and ultimately stuck pipe events and require relatively high mud weights to maintain wellbore stability. LWD azimuthal acoustic technology, free from chemical sources, was used for the first time both in drilling and wipe modes to facilitate time-lapse field stress and wellbore stability analysis.

Principal stress orientations were identified from three different sources, including borehole breakouts from azimuthal acoustic caliper, density image, and acoustic anisotropy evaluation. The results were then compared with the existing offset well data and an existing geomechanical 3D model. Variations in observed stress orientation, seismic reflection pattern, and pressure history in offset wells were used to map a fault that is responsible for bypassed oil and for the occurrence of tar and gas. The interpretation was extended to other low throw strike-slip faults; additional fault compartments were identified that could affect the pressure maintenance scheme of the field.

This paper discusses the planning, design, and use of LWD azimuthal acoustic technology in this case history well. It also describes the viability, integrity, and reliability of the interpreted results and their use in a detailed geological interpretation in terms of stress orientation, fault trapping, and areal fluid variation. The optimization of real-time drilling operations and petrophysical data acquisition requirements are also investigated to improve future field development and overall reservoir management strategies.
Optimal Field Development of Immature Clastic Heterogeneous Brownfield with Waterdrive: Subba Field, South Iraq Case Study
Authors: Al-Khazraji Ahmed Khalil , Shuker Muhannad T.
Published: September 2015

This paper presents an optimization analysis of different development options of Nahr Umr reservoir in Subba oilfield. Nahr Umr reservoir is a highly heterogeneous clastic reservoir with moderate edge a bottom waterdrive and it has a short production history for six months. Many different development scenarios have been conducted in this study to test possible predictive scenarios to determine the most significant development option. The black oil commercial software simulator, Eclipse-100 was used to study fluid flow in the reservoir and to predict the future behavior of reservoir. The prediction scenarios considered in this study include, natural depletion through the existing wells, determine the optimal number of infill producers, and waterflooding option through conducting peripheral and five-spot patterns. The development plan assumed to commence at January 2017, then couple of runs using simulator flow model were conducted for ten years. The waterflood sceneries startedup on January 2023 and January 2027 for inverted five-spot and peripheral patterns respectively with 58 producers and 66 injectors for peripheral pattern and 102 producers and 77 injectors for inverted five-spot pattern. The results are analyzed based on economic criteria to optimize the number of infill drilling. The optimization of development options was achieved based on net present values analysis.
Supramolecular Viscoelastic Surfactant Fluid for Hydraulic Fracturing
Authors: Yang Jiang , Lu Yongjun , Zhou Caineng , Cui Weixiang , Guan Baoshan , Qiu Xiaohui , Liu Ping , Ming Hua , Qin Wenlong , Ji Sixue
Published: September 2015

This paper studied a new fracturing fluid based on a supramolecular complex of associative polymer and vsicoelastic surfactant. The crosslink complex gel was based on weak physical attractive forces such as van der waals, hydrogen bonding and electrostatic interaction between associative polymer and wormlike micelle of viscoelastic surfactant. The fluid contained surfactant ten times less than that of conventional viscoelastic surfactant fracturing fluid. The combination of viscoelastic surfactant and associative polymer synergistically enhances the viscosity ten times more than that of the individually components alone. The fluid system was optimized by experimental design. The microstructure of wormlike micelle was verified by cryo-transmission electron microscopy. The fluid is shearing-stable at high temperature for 1 hour. The dynamic rheological properties of the new VES fluid showed high viscoelasticity, in which elastic moduli is higher than loss moduli at angular frequency 0.1 rad/s. The proppant transport test in a large-scale fracture simulator showed good proppant suspension ability. The fluid has 50% lower formation damage than that of conventional guar. The fluid was prepared with less additives and formed gel instantly which can be mixed on the fly in the field. The gel can be completely broken with almost no residue. Field application of the new fracturing fluid in a gas field showed the enhancement of gas production over 100%. The fluid has 20% lower friction pressure than that of guar fluid. Hence, the new supramolecular viscoelastic surfactant gel is an effective fracturing fluid with less formation damage.