bluuebunny/crossref_metadata_2025 huggingface dataset:
Fracture-Width Estimation for an Arbitrary Pressure Distribution in Porous Media
Authors: Todd B.. , Choudhary Y.. , Bhamidipati S..
Published: September 2011

Accurate estimation of fracture width is necessary for successful hydraulic fracturing or FracPac treatments. This information becomes even more critical when most of the fluid leakoff is forced through the proppant pack and out through the tip of the fracture during hydraulic fracturing or FracPac treatments. With the development of new, low-leakoff fluid systems, the coupling of fluid flow through porous media and subsequent pressure responses must be incorporated in predicting fracture-width profile.

The generalized width equations, although well-known, are seldom solved for cases other than constant pressure throughout the fracture or for simple pressure distributions. This paper demonstrates how these complex fracture-width equations can be solved for an arbitrary pressure distribution in a simplified approach. The generalized width equations for fracturing calculate a fracture’s width along its length or radius, w(x) or w(r), given a pressure profile, p(x) or p(r).

Two main width techniques are discussed, one based on a modified Perkins-Krech approach and the other on a corrected Valko-Economides approach. A comparison to the Jaeger-Cook deflection equation is made. In the Perkins-Krech and the Jaeger-Cook cases, the method of superposition is used. In the Valko-Economides case, the pressure is fit with a polynomial equation, and the integration is carried out term by term. The results are comparable with a finite element analysis (FEA) model, and good agreement has been observed. Examples are presented on how these techniques can be set up in spreadsheets, allowing the engineer to investigate concepts like "dry tip" and stresses around a fracture perimeter.
Reservoir Simulation and Modeling Based on Pattern Recognition
Authors: Mohaghegh Shahab D.
Published: September 2011

In this paper a new class of reservoir models that are developed based on the pattern recognition technologies collectively known as Artificial Intelligence and Data Mining (AI&DM) is introduced. The workflows developed based on this new class of reservoir simulation and modeling tools break new ground in modeling fluid flow through porous media by providing a completely new and different angle on reservoir simulation and modeling. The philosophy behind this modeling approach and its major commonalities and differences with numerical and analytical models are explored and two different categories of such models are explained. Details of this technology are presented using examples of most recent applications to several prolific reservoirs in the Middle East and in the Gulf of Mexico.

AI-Based reservoir models can be developed for green or brown fields. Since these models are developed based on spatio-temporal databases that are specifically developed for this purpose, they require the existence of a basic numerical reservoir simulator for the green fields while can be developed entirely based on historical data for brown fields. The run-time of AI-Based reservoir models that provide complete field responses is measured in seconds rather than minutes and hours (even for a multi-million grid block reservoir). Therefore, providing means for fast track reservoir analysis and AI-assisted history matching are intrinsic characteristics of these models. AI-Based Reservoir Models can completely substitute numerical reservoir simulation models, work side by side but completely independent or be integrated with them in order to increase their productivity.

Advantages associated with AI-Based Reservoir Models are short development time, low development cost, fast track analysis and have the practical capability to quantify the uncertainties associated with the static model. AI-Based Reservoir Model includes a novel design tool for comprehensive analysis of the full field and design of field development strategies to meet operational targets. They have open data requirement architecture that can accommodate a wide variety of data from pressure tests to seismic.
In-Situ Mechanical and Functional Behavior of Shape Memory Polymer for Sand Management Applications
Authors: Yuan Y.. , Goodson J.. , Johnson M.. , Gerrard D..
Published: September 2011

Pumping a gravel-slurry between a downhole screen and the rock matrix has been used to prevent production of undesirable solids or sand from the formation in traditional oil and gas completions. Recently developed expandable technology attempts to eliminate this operation by expanding metallic sand control screens against the wellbore. However, a problem with this process is borehole irregularity. It is desirable to have a smart downhole screen structure that is capable of self-expanding and conforming to the borehole surfaces in certain downhole conditions. Use of an advanced shape memory polymer structure offers breakthrough performance for sand management applications. Proper characterization and full understanding of the mechanical and functional behavior of the shape memory polymer structure in simulated downhole pressure, temperature, and fluid conditions is critical for successful applications.

This study used a high-pressure/high-temperature in-situ mechanical test system and test method to characterize the in-situ hot-wet mechanical and functional behavior of the shape memory polymer foam. This included deployment and contact pressure development functional properties, compressive and time-dependent stress-relaxation and creep properties. These properties were determined during immersion in a fluid environment at various temperatures under ambient pressure and 3,000-5,000 psi hydrostatic pressure. Effects of the test temperature, fluid condition and the hydrostatic pressure on mechanical and functional properties of the shape memory polymer foam were identified. Study results were used to establish the operational window of shaped memory polymer screen as a sand control solution.
Game-Changing Technology Developments for Improving Operational Efficiencies in Deepwater Well Completions
Authors: Kessler Calvin , Hill Jim , Earl Tyson
Published: September 2011

A new-generation electro-mechanical downhole power unit for setting and retrieving packers, bridge plugs, whipstocks, and other downhole devices has been recently developed and globally deployed. The new downhole power unit – Intelligent (DPU®-I system), is designed to operate at high temperatures and extreme high pressures (400°F, 30 Kpsi), while providing up to 100 Klbs of setting force. The high linear force for either setting or retrieving is independent of hydrostatic pressure and provides a cost-effective alternative to jointed-pipe interventions, which were previously required to obtain high setting forces. The e-line-conveyed DPU-I system, with its high setting force, has been successfully used numerous times in deepwater wells and has shown to save in excess of one day’s rig time for setting sump packers or other devices in ultra-deep well conditions compared to jointed-pipe intervention. New to the industry is the ability to monitor in real time at the wellsite and remotely via satellite communications the downhole line tension, tool acceleration, stroke length, the setting force, and the rate at which the force is being applied during the setting operation as well as the force at which the DPU-I system detaches from the downhole device. This allows well-completion experts to remotely monitor the setting or retrieval operations 24/7 and provides a record of the setting operation for risk mitigation and developing and improving best practices.

The slow-controlled setting operation enables the slips or other anchoring mechanisms in the device to be set and to fully engage the casing/tubing and elastomer sealing elements to conform to the casing or tubing ID, which is extremely critical in highly-deviated well conditions and when casing or tubing with high-rockwell hardness is used. Unlike setting devices that use explosives, military or governmental escorts are not required. Single-lift, heli-operations can be used. Radio silence operations are not required, and there is no non-productive time associated with tool re-dressing between runs. Tool sizes are available for well intervention from 2–3/8–in. tubing through all casing sizes and can be tractor conveyed in high-angle or horizontal wells.
Analysis and Performance Measurement of Axial Vortex Separator (SVA) for Liquids/Gas Mixture
Authors: Castellanos J.. , Quijada V.. , Kenyery F..
Published: September 2011

Nowadays, the efficient separation of multiphase mixtures has a great importance in offshore installations where space is limited. In this case, the use of Compact Cyclonic Separators (CCS) has gained popularity because it is simple, compact, and economical to manufacture and operate. Its operation field is established on the basis of superficial velocities of liquid and gas within the separator, being limited by the occurrence of two phenomena: the Liquid Carry-Over (LCO) and the Gas Carry-Under (GCU) in the discharge pipes of gas and liquid respectively. Taking into account this two main phenomena, in the present experimental study was determined the operation field and performance of an Axial Vortex Separator (SVA) of 3’’ in diameter for a water-air mixture flow. SVA is composed by two vertical concentric tubes. The inner tube has a stator to generate a vortex centrifugal force which combined together with the buoyancy and gravity forces can separate the phases. SVA behavior was studied for different relative positions of the concentric tubes and two different angles from the stator blades. The experimental results were used to analyze the accuracy of mechanistic models available in literature for prediction of LCO and the flow patterns presented in the SVA. A good agreement was accomplished. Additionally, the operational envelope of SVA with 0% and 1% of LCO was determined. The SVA minimum separation efficiency in the experimental tests carried out was 99%.
Partially Separated Meta-Models with Evolution Strategies for Well Placement Optimization
Authors: Bouzarkouna Z. , Ding D.Y. , Auger A.
Published: September 2011

Finding the optimal location of non-conventional wells increases significantly the project’s Net Present Value (NPV). This problem is nowadays one of the most challenging problems in oil and gas fields development. When dealing with complex reservoir geology and high reservoir heterogeneities, stochastic optimization methods are the most suitable approaches for optimal well placement. However, these methods require in general a considerable computational effort (in terms of number of reservoir simulations, which are CPU time demanding).

This paper presents the use of the CMA-ES (Covariance Matrix Adaptation – Evolution Strategy) optimizer, which is recognized as one of the most powerful derivative free optimizers, to optimize well locations and trajectories. A local regression based meta-model is incorporated into the optimization process in order to reduce the computational cost. The objective function (e.g., the NPV) can usually be split into local components referring to each of the wells: it depends in general on a smaller number of principal parameters, and thus can be modeled as a partially separable function. In this paper, we propose to exploit the partial separability of the objective function into CMA-ES coupled with meta-models, by building partially separated meta-models. Thus, different meta-models are built for each well or set of wells, which results in a more accurate modeling.

An example is presented. Results show that taking advantage of the partial separability of the objective function leads to a significant decrease in the number of reservoir simulations needed to find the "optimal" well configuration, given a restricted budget of reservoir simulations. This approach is practical and promising when dealing with a large number of wells to be located.
Laterals Stimulation Method
Authors: Freyer R.. , Shaoul J. R.
Published: September 2011

Due to reduced availability of high quality reservoirs, more wells require stimulation. The current default method for stimulation is hydraulic fracturing, using either proppant or acid to keep the fracture open. In many environments, Proppant or Acid Fracturing is a good solution to increase productivity. Some of the unresolved challenges with fracture stimulation are reservoir related such as the uncertainty about whether the fracture will grow through different reservoir layers, potentially contacting unwanted water. Operational challenges are environmental, cost, operational complexity and availability of equipment and competent personnel. Onshore fracturing experience can build on the learning of hundreds of wells to optimize the fracture stimulation process, but this is not possible in an offshore environment.

A new completion based stimulation solution is developed to be simple and efficient without environmental impact and with significantly lower cost than current solutions. Several reservoirs have been simulated to investigate the long term production and recovery using the method. The relatively new well geometries require further understanding to apply the technology. A study on offshore well cost has been made.
Matrix Stimulation in the Candidate Wells Indicate Unexpected Performance Improvement in a Dolomitic Carbonate Reservoir
Authors: Hashemi A.. , Sajjadian S.. , Sajjadian V. A. , Karimi S..
Published: September 2011

Field studied is one of the ramp types of carbonate reservoirs. The reservoir under studied consists of three layers which have been affected by Karstification. The flow test has been implemented after the perforation operation. The results have shown that the designed plateau can not be met i.e. the current field production by considering maximum efficient rate cannot manage the target production. By analyzing the Pressure Test Analysis some wells have been chosen as underperforming wells.

Matrix stimulation is one of the conventional methods to increase the productivity index of the formations. The expected production plateau in this dolomitic carbonate oil field in the south west of Iran is met by Matrix Stimulation. Based on the theoretical improvement of the Pressure Test Analysis (PTA), past experience in the field and reservoir sedimentology, the candidate wells are selected. The matrix stimulation technique is determined to theoretically reduce the skin factor to -2 or -3 as mentioned in the literatures. After well ranking, the stimulation campaign is practiced.

Field experience indicates unexpected production improvement due to heterogeneous dolomitic nature of the reservoir. A comprehensive study is conducted to find out the reasons of this 3 to 4-fold production improvement i.e. the log, core and drilling mud is compared and reservoir model is investigated. Moreover the welltest data before and after the stimulation are investigated. Before stimulation in build up data geochoke phenomena is detected while after stimulation is vanished. One well is penetrated to most heterogeneous section of the reservoir model and geochoke phenomena are simulated. Therefore the idea of removing geochoke phenomena around the wellbore is raised.
Novel High Speed Telemetry System with Measurements Along the String Mitigate Drilling Risk and Improve Drilling Efficiency
Authors: Veeningen D..
Published: September 2011

Novel systems such as the wired-pipe or networked drillstring telemetry system have allowed broadband communication with downhole tools in various operating areas around the world, including in deepwater. Two capabilities are vital to offer operators and service companies with cost effective drilling and completion in challenging scenarios:

High speed: real-time, bi-directional data transfer at a rate of 57,600 bits per second (bps) enables downhole and subsurface conditions to be measured and controlled, Measurements all along the string: annular pressure and temperature measurements distributed at network nodes beyond just at the drill bit enable early warning of developing trouble events.

This paper describes cases where the broadband network provided downhole information for identifying poor hole cleaning, determining sweep efficiency, revealing cutting accumulation and recognizing pack offs early on.

Further, examples are described that improved drilling risk mitigation by the capability to measure as many as 45 different drilling dynamics parameters that are updated every few seconds revealing bit whirl, stick slip, lateral and axial movement while drilling trouble zones.

The successful mitigation of downhole vibration resulted in a 68% increase in time on bottom and a 58% increase in rate of penetration (ROP). Annular pressure evaluation all along the drillstring ensured adequate hole cleaning in challenging wellbores.
Effect of Initial Gas Saturation on Steam Assisted Gravity Drainage Process
Authors: P. Oskouei S. Javad , Maini B. , Moore R. G. , Mehta S. A. , Yazdani Ali
Published: September 2011

Cold Heavy Oil Production with Sand, CHOPS, is a primary recovery method commonly used in many Canadian heavy oil reservoirs. In spite of its commercial success, the oil recovery factors achievable with this process range between 5 to 20 percent. In order to recover more oil from primarily depleted reservoirs, Steam Assisted Gravity Drainage (SAGD) process can be considered. However, the performance of SAGD process is likely to be negatively affected by the initial gas saturation present in such depleted reservoirs. Unfortunately, no systematic study of the effect of initial gas saturation on SAGD performance has been reported.

This paper presents an experimental evaluation of the effect of initial gas saturation on SAGD performance using physical models. Different gas saturation levels were established in the model by modifying the model packing and saturating techniques. High pressure physical model experiments were carried out by injecting steam at controlled rate and producing the oil from the production well at constant pressure. The oil production behavior was analyzed to evaluate the effect of initial gas saturation on thermal efficiency of the process. Based on the results, it is possible to conclude that initial gas saturation of about 9 percent, or higher, accelerated heat dissipation and retarded the formation and growth of the steam chamber. Due to the higher relative permeability of steam in the gas saturated zone, it becomes difficult to confine the steam in a chamber as seen in the conventional SAGD. The temperature in the steam zone was noticeably below the steam saturation temperature and the oil production rate was substantially lower compared to similar test without the gas saturation. The results strongly suggest that SAGD would not be a viable option in Heavy oil reservoirs containing high free gas saturations.
Geochemical Modeling and Experimental Evaluation of High-Ph Floods: Impact of Water-Rock Interactions in Sandstone
Authors: Kazempour Mahdi , Sundstrom Eric , Alvarado Vladimir
Published: September 2011

Alkaline flooding, either for enhancing heavy oil recovery, or in alkaline-polymer (AP) and alkaline-surfactant-polymer (ASP) flooding for lighter oils, represents an important EOR strategy. Injection of alkaline solutions leads to mineral dissolution and precipitation with likely resulting changes in permeability and porosity of reservoirs, which in turn alter solution pH. Accurate prediction of pH, alkali consumption and aqueous chemistry changes are required to design suitable chemical flooding blends. Excessive consumption of alkali can result in degradation of flood performance and lower than expected oil recovery.

We report results of state-of-the-art geochemical simulations for sandstone reservoir mineral assemblages and alkali solutions (NaOH, Na2CO3, and NaBO2) employed in AP and ASP formulations. The strategy has been tested for conditions of the State of Wyoming in Minnelusa reservoir and Berea sandstones. Single-phase high-pH floods were completed in the lab to calibrate and validate geochemical simulations.

Results show that rock-fluid interactions are a strong function of mineral type and amount, alkaline solution injection flowrate, and composition of injected and formation water. It is found that anhydrite has a significant impact on pH buffering capacity, water chemistry changes and permeability damage against conventional alkali agents in chemical flooding particularly in the case of Na2CO3, but no significant pH buffering is observed during NaBO2 flooding. Experimental data and model results show that the pH-buffering effect is maintained even after several pore volumes of alkaline solution are injected, if a sufficient fraction of relevant minerals are present. Comparison between linear core and field flooding simulations show that short reaction times tend to minimize these effects and may lead to conclusions that cannot be readily transferred to field cases.

By applying reaction-transport modeling, the design of chemical flooding can be improved and formulation effectiveness losses caused by reservoir mineralogy can be avoided, even in cases where traditional laboratory screening procedures would indicate a suitable formulation for chemical flooding.
A New Dimension Added to the Hydraulic Fracture Stimulation for a Volcanic Reservoir Based on Microseismic Monitoring
Authors: Mishra Satyabrata , Gupta Anish , Mathur Mohit , Purusarthy Naresh , Wenk Andrew
Published: September 2011

The Raageshwari Deep Gas (RDG) Field in the Barmer Basin, India is a lean gas condensate reservoir, with excellent gas quality of ~80% methane, low CO2 and no H2S. The productive zones are in volcanic rocks and volcanogenic sediments. From a permeability perspective, the RDG reservoir is similar to typical tight gas reservoirs in other parts of the world which cannot be commercially developed without large-scale hydraulic fracturing. Recent RDG hydraulic fracture treatments have been monitored with microseismic mapping technology. The microseismic data was acquired in June 2010 to quantify the trend of hydraulic fracture networks induced in a 5-stage stimulation program. The recorded P and S wave events were subsequently mapped in 3D space by fracture stage (in time) to effectively represent the onset, propagation and trends of the fractures and the extent, overlap or inter-connection of the resulting fracture networks. The initial objective of conducting microseismic mapping was only to calibrate the existing fracture simulator. Earlier hydraulic fracture treatments had been conducted with a conventional gas condensate frac design in mind, with targets of ~100m of frac length and a dimensionless fracture conductivity (FCD) ranging from 5-10. The initial frac schedules were designed with large pad and proppant stage volumes (~275,000lb of 20/40 ISP and 16/30 ISP). The efficacy of these fracture treatment designs was to be verified with the microseismic mapping technology. It was found that RDG does not have the typical tight gas reservoir architecture which was assumed for the initial frac designs, but consists of tight matrix porosity contained within a very complex network of natural fractures and planes of weakness with conjugate jointing. Hence the conventional fracture design was changed to deal with such fracture network for future fracturing campaigns.
Integrated Geo-Statistical Modeling – An Effective Tool to Meet the Exploration Challenge of Low Porosity Carbonate Reservoir within Najmah-Sargelu Formation, Kuwait
Authors: Nath Prabir Kumar , Prasad Raghav , Khan Badruzzaman , Singh Sunil Kumar , Abu-Taleb Reyad , Bader Sara
Published: September 2011

The emergence of low porosity carbonate lithofacies of Najmah-Sargelu Formation as a commercial hydrocarbon play has led to change the exploration perspective of these formations. Several wells from different structures in Kuwait has shown the production potential of light oil@ 1000–4000 BOPD and natural gas 3.8–19.0 MMSCFD. The production has been obtained from bituminous mudstone, wackestone and algal limestone from Najmah-Sargelu Formation.

Understanding the geometry and distribution of carbonate lithofacies of Najmah-Sargelu Formation is a major exploration challenge. Geo-statistical 3D model is a dynamic tool, which has been utilized to quantify the geometry and spatial distribution of carbonate lithofacies vis-a-vis its continuity.

A careful geo-statistical workflow was evolved to address the major challenges of these reservoirs. An artificial intelligence, neural network was trained against cored section and subsequently applied in the noncored sections for lithofacies prediction. Sequence Stratigraphic framework, seismic grid and 3D geo-statistical modeling were integrated to create a geological model. Core-measured rock property data were analyzed to illustrate the distributions of core porosity and permeability of Najmah-Sargelu lithofacies. The distribution of internal properties and heterogeneity has been quantitatively described as the relationship of a reservoir facies within a sequence stratigraphic framework. Spatial estimation of lithofacies and reservoir properties provides insight into the deposition and diagenetic process of the reservoir units.

The depositional pattern and connectivity analysis suggests a ramp setting in inner shelf environment of deposition with three major alternate transgressive and regressive sequences. An integrated geo-statistical modeling has resulted in depicting the internal geometry and connectivity of low porosity carbonate lithofacies thereby reducing the uncertainty in volumetric assessment in the delineation phase of Najmah-Sargelu Formation.
Gas Condensate Flow Around Deviated And Horizontal Wells
Authors: Ghahri P. , Jamiolahmady M. , Sohrabi M.
Published: September 2011

Drilling deviated and highly deviated wells (DWs) in gas condensate reservoirs is aimed at increasing reservoir reach and reducing pressure drop, thus improving well deliverability. The flow of gas and condensate around the wellbore when the pressure drops below dew point pressure is affected by phase changes and variation of relative permeability (kr) with velocity and interfacial tension (IFT). Flow simulations and well productivity calculations for these near critical fluid systems and in the case of such three dimensional DW geometries, are more complex compared to those of a 1D radial vertical well. There are limited sensitivity studies dedicated to such important petroleum engineering situations.

We have developed various mathematical single-well models simulating flow of gas and condensate around such wells. A comprehensive sensitivity study (over 500 simulation runs) was then conducted to evaluate the impact of pertinent parameters on the DWs performance with some important practical findings. We have also considered horizontal wells, which are DWs with the deviation angle of 90°. The results demonstrated that the performance of DWs strongly depends on wellbore gas fractional flow (GTRw) and velocity. For instance, for a given pressure drawdown, the coupling effect (increase in kr due to an increase in velocity or decrease in IFT), improves the performance of highly DWs at short well lengths, whilst the negative impact of high velocity inertia (a decrease in kr by an increase in velocity) is more pronounced at higher GTRw, smaller wellbore radius and higher reservoir thickness values. For long DWs the productivity ratio (deviated to vertical well fluid production rate ratio) does not vary with GTRw. However, for short DWs, it increases for moderate condensate fluid but decreases for the rich gas condensate fluid. This is due to the variation of contribution of coupling and inertia with GTRw in the deviated and vertical wells.
Multi-Scale and Multi-Physics Methods for Numerical Modeling of Fluid Flow in Fractured Formations
Authors: Qin Guan , Gong Bin , Bi Linfeng , Wu Xiaohui
Published: September 2011

Natural fractures reside in various subsurface formations and are at various length scales with different intensities. Fluid flow in fractures, in matrix and between matrix and fractures are following different flow physics. It is thus a great challenge for efficiently modeling and simulation of fluid flow in fractured media due to the multi-scale and multi-physics nature of the flow processes.

Traditional dual porosity and permeability approach represents factures and matrix as different continuum. The transfer functions or shape factors are derived to couple the fluid flow in matrix and fractures. The dual porosity and permeability model can be viewed as a multi-scale method and the transfer functions are used to propagate fine-scale information to the coarse-scale reservoir simulation. In this paper, we perform a detailed study to better understand the optimal way to propagate the fracture information to the coarse-scale model based on the detailed fracture characterization at fine-scale. We use two different upscaling procedures. One is the multiple sub-region method (SPE 102491) that is based on the dual porosity and permeability approach. The other is using Stokes-Binkman equation (SPE 105377) to solve the fine-scale flow problem and then deriving the upscaling information from the fine-scale solution.

The Discrete Fracture Modeling (DFM) approach is used to represent each fracture individually and explicitly. Then, both the multiple sub-region method and Stokes-Brinkman equations are used to solve for fine-scale flow information based on the DFM. The fine-scale information captured by these two approaches are used in coarse-scale reservoir simulations respectively. The two approaches are compared in terms of how well they preserve key fine-scale flow dynamics in the coarse simulations. We then propose an efficient and accurate upscaling workflow for numerical modeling of fractured media, which will extends predicting capability in efficient development of fractured reservoirs.
A Systematic Analysis to Select an Optimized Perforating Interval as a Key Factor for Improved Oil Recovery: Impact of Dynamic and Static Petrophysical Properties on Well Production
Authors: Miranda Luis Javier , Angel Franklyn
Published: September 2011

Unexpected high water cut, sand production and low productivity have negatively affected multiple wells producing from reservoirs in the Apure Area fields of southwest Venezuela. As a result, multiple well interventions have been conducted which increase costs and delay oil production. Several of these wells are inactive today but could be potential candidates for reactivation by reperforating prospective intervals. In several cases, the selection of the perforated interval for these reservoirs is considered inefficient because the effects of multiple dynamic and static petrophysical properties are not considered in the current method, such as vertical permeability, anisotropy or pore throat size, among others. We propose a systematic analysis to optimize the interval to be perforated for inactive and new wells that will minimize such related production problems.

The proposed analysis involves the incorporation of multiple variables (type of perforation, interval to perforate, distribution of reservoir fluids, fluid of completion, etc.) to consider the effects of the different petrophysical properties on well productivity. The latter are obtained by integration of rock-core data and conventional and advanced well logs acquired in open and cased hole. In addition, we conducted a sensitivity study to analyze other parameters, such as perforating method and production behavior. A technical analysis was performed to select the optimum design based on different conditions leading to a complete study. The results show that the optimum interval selection and type of perforation to be implemented should not involve only a simple net pay consideration but also multiple factors such as reservoir properties, reservoir fluids distribution and perforating method that play a key role in well production behavior. Finally, we present field applications that confirm the success of this method that enables the reliable selection of an optimized perforated interval.
Challenges and Solutions for Automated Wellbore Status Monitoring - Breakout Detection as an Example
Authors: Wessling Stefan , Dahl Thomas , Pantic Dinah
Published: September 2011

Automated real-time wellbore stability services contribute to a significant reduction of non productive time. Automation reduces the workload, supports the decisions of engineers and facilitates simultaneous remote supervision of multiple wells. The industry is approaching first steps towards automated drilling; however the accomplishment of mature automated systems requires further extensive research and development. In particular, automated real-time wellbore stability systems require a high level of confidence because decisions based on the results can have significant consequences. Robust, reliable and intensively tested algorithms need to be developed and experience has to be gathered by comprehensively supervised field testing.

This paper presents an algorithm and its applications for the automated monitoring of wellbore status. Taking the detection of breakouts on images of the borehole wall as an example, observations and experience gained during the development of such a system are documented. A breakout detection system is fed by formation evaluation and drilling dynamics logs acquired by downhole tools during the drilling operation. The automated breakout detection algorithm is able to scan image log data to identify the existence or non-existence of breakouts and to deliver parameters such as the breakout orientation and width for the calibration of in-situ Earth stress directions and magnitudes needed for calculation of the shear failure gradient (one of two lower bounds for the pressure window).

The automatic detection of breakouts on low-resolution resistivity and density real-time images proves the algorithm's applicability while drilling. The tests were also used to identify operating constraints, i.e., circumstances (especially of geological nature) under which the system may deliver erroneous information. Users need to be aware of such operating constrains to have confidence in the algorithm's reliability.
Engineering Workflows Provide Integrated Operations and Streamline Real-Time Production Optimization
Authors: Barbarino Sebastiano , Sarmiento Salvador , Cuadras Romel , Suarez Jose , Hung Mailing , Manzanilla Franklin
Published: September 2011

This paper explores the results of one operator's successful implementation of a workflow-based solution for real-time Production Surveillance and Optimization of a large on-shore field in Mexico. We will also examine the fundamental aspects of large-scale workflow delivery in a real-world environment – in this case, involving over 200 wells producing over 200,000 STBD, 50+ users, multiple and often conflicting sources of data (ex. Field vs. SCADA), and integration of production modeling applications from multiple vendors.

The solution combines automation of production modeling workflows, real-time monitoring, Surveillance-by-Exception, and virtual integration of 8 data sources – including real-time, operational, well test, field data, and others – into a single and user-friendly environment. It has been designed with the asset in mind, and has delivered their goals of: Maximize total oil production,Minimize downtime,Virtual Well Flowrate Metering,Well performance overview, providing a single point-of-access to all available information,Standardize engineering processes across the asset, with a heavy emphasis on automation and analytics.

The "intangible" benefits of standardizing processes and providing readily-available access to information are seen as key enablers of the more directly measurable economic benefits.

Prior to the implementation of this solution, it was demonstrated that a significant portion of the asset engineers' time was spent on gathering data from multiple sources. Such activities were manual and error-prone, and led to data duplication, data inaccuracies, and - most importantly - potential for decisions to be made based on incomplete information.

The new solution addresses all of these challenges. Integrated reporting and surveillance-by-exception methods ensure that engineers' time is now focused on engineering issues – not data gathering. "Live links" to all sources ensures that data duplication is no longer an issue. And workflow-based automation have brought the various pre-existing Well, Production Network, and Reservoir modeling tools "Online", so they can be incorporated into daily operational activities and decision-making.

The work is significant as a successful implementation of a large-scale production optimization solution configured to established operator best practices. In an age when operators are faced with declining production rates, smaller discoveries, and a "graying" workforce, such solutions allow operators to do more with less and deliver maximum asset value.
Probabilistic Performance Forecasting for Unconventional Reservoirs with Stretched-Exponential Model
Authors: Can B. , Kabir C. S.
Published: September 2011

Reserves estimation in an unconventional-reservoir setting is a daunting task because of geologic uncertainty, complex flow patterns evolving in a long stimulated-horizontal well, among other variables. To tackle this complex problem, we present a reserves-evaluation workflow that couples the traditional decline-curve analysis with a probabilistic forecasting frame. The stretched-exponential production decline model (SEPD) underpins the production behavior. Our recovery appraisal workflow has two different applications: forecasting probabilistic future performance of wells that have production history and new wells without production data. For the new field case, numerical model runs are made in accord with the statistical design of experiments for a range of design variables pertinent to the field of interest. In contrast, for the producing wells the early-time data often need adjustments owing to restimulation, installation of artificial-lift, etc. to focus on the decline trend. Thereafter, production data of either new or existing wells are grouped in accord with initial rates to obtain common SEPD parameters for similar wells. After determining the distribution of model parameters using well grouping, the methodology establishes a probabilistic forecast for the individual wells.

This paper presents a probabilistic performance forecasting methodology in unconventional reservoirs for wells with and without production history. Unlike other probabilistic forecasting tools, grouping wells with similar production character allows estimation of self-consistent SEPD parameters and alleviates the burden of having to define uncertainties associated with reservoir and well-completion parameters.
Automating Decline Curve Analysis in an Integrated Reservoir Management Portal
Authors: Nuaim Ahmed , Madani Husameddin , Seemann Dennis , Holdaway Keith
Published: September 2011

Estimating reserves and predicting production in reservoirs has long been a challenge. The importance of performing accurate analysis and interpretation of reservoir behavior using only rate and pressure data as a function of time or cumulative production is fundamental to assessing remaining reserves and for forecasting production. An interactive system was developed to assist in Decline Curve Analysis (Cartesian, Exponential, Harmonic and Hyperbolic) and Production Forecast in an Integrated Reservoir Management environment.

This paper introduces a refreshingly intuitive navigation of the disparate data sources and input parameters aligned with a comprehensive suite of forecasting models wrapped into a web-based solution. The user is enabled with interactive graphical output to extensive "what-if" combinations of critical input parameters across multiple forecasting models. Whether working with oil or gas reservoirs, the user has access to a rich compendium of forecasting techniques that detail accuracy indicators and interactive graphs. The relationship, for example, between P/Z and cumulative gas production for typical gas reservoirs can be studied by calculating pressure response to various modes of gas production and water encroachment.

The motivation of designing a web-based DCA in an integrated portal was the need of reservoir engineers to establish a one stop information analysis integrated platform. This platform integrates different data sources and applications used for analyzing engineers' fields and reservoirs saving them the time needed to search and manipulats the data.
Transforming Operations with Real Time Production Optimization and Reservoir Management: Case History Offshore Angola
Authors: Paulo Jeronimo , Taylor Deidre A. , Isichei Obi , King Marty , Singh Gagan
Published: September 2011

The subject field is located 50 miles offshore Angola in ∼1200' of water. The compliant piled tower that supports this development in Block 14 is one of the largest manmade structures in the world. The 46-well development plan includes both wet and dry trees. The multi-layered reservoirs are heterogeneous in nature. To extract the most value from this development, Chevron has developed and deployed an integrated solution that uses people, processes and technology to improve performance. In 2002 Chevron began exploring how integrated digital solutions could help better manage the reservoirs, wells and facilities. Since that time, a fully fledged i-field™ program was developed with a vision for transforming operations through technology. It's about making sure the right people have the right information at the desired frequency in a usable format at the right time to make the best decision. It's about teamwork and collaboration across function and distance. It's about providing people the time and space to develop creative alternatives and solutions to effectively manage the daily and longer term challenges.

The Production Optimization Solution for the subject field was successfully deployed in September 2010. The solution is designed to improve production engineering productivity, increase production and recovery by optimizing overall field management, and decrease response time through early problem detection. Two initial engineering workflows were deployed along with an asset overview dashboard that displays key information, trends and results. After a rigorous evaluation process, a project team was created to develop the engineering workflows that make use of nodal analysis and pressure transient analysis tools for field and model management. A 3rd party vendor was selected to design and manage the data and application integration required to successfully implement the solution.

This paper will detail the development and deployment of this integrated solution that is allowing the engineers to spend more time on technical work, respond quicker to anomalies, and make better, faster decisions. It will also discuss the requirements for success that include change management, training, support and organizational capability.
Modified Mathematical Model for Fines Migration in Oilfields
Authors: Zeinijahromi A.. , Machado F.. , Bedrikovetsky P..
Published: September 2011

Permeability decline during corefloods with varying water composition, especially with low salinity water, has been widely reported in the literature. It has often been explained by the lifting, migration and subsequent plugging of pores by fine particles, which has been observed in numerous core flood tests with altered water composition. In the present paper, we derive a new system of governing equations describing fines mobilisation, migration and subsequent permeability decline for 1-phase and 2-phase flows. In large scale approximation, the mathematical model for 2-phase flow with induced fines migration is equivalent to polymer flooding model. It allows taking advantage of the polymer flooding option for the Eclipse black oil simulator in order to model waterflood with low salinity water, where the induced fines migration and permeability damage can be considered to provide a relatively simple method for mobility control during waterflooding. The modelling showed that permeability decline in the water swept zone, caused by the alteration of the injected water composition and induced fines migration, may be able to improve waterflood performance by delaying water breakthrough and reducing the water cut.
Barriers to the Implementation of Real-Time Drilling Operations Strategy
Authors: Crawley C.. , Rizvi A..
Published: September 2011

Many industry insiders and analysts believe that the creation of real-time operating centers to achieve drilling optimization is the key to solving numerous challenges encountered by the industry. Even with a significant investment and the development of state-of-the-art facilities by major operators, however, the incorporation of real-time center operations in the field has occurred more slowly than anticipated.

In 2009, the SPE Real-Time Optimization Technical Interest Group (RTO TIG) surveyed the drilling community, including oil companies, operators, and consultants, to assess the progress of the industry toward drilling optimization through the use of real-time operating centers. This survey identifies barriers to real-time center use and adoption, and assesses the use of technical and business tools at each stage of the real-time process, ranging from data collection to decision making and field action.

This paper summarizes the results of the survey and analyzes its findings. The survey covers the entire value chain in oilfield drilling services, from preliminary modeling and planning to actual drilling. With data collected from more than 150 respondents, the survey findings indicate that the industry perceives that few substantial obstacles remain in the adoption of real-time centers and that progress in real-time drilling optimization is being made. Although many respondents predict that the remaining barriers will eventually be overcome, the RTO TIG believes that by identifying and highlighting these barriers, and by exploring the most persistent barriers to adoption, we can illuminate methods by which the industry can achieve faster gains in real-time adoption and performance.

The survey finds that many companies have acquired the technology necessary for real-time operations, yet have failed to achieve real-time performance in the implementation of this technology. This paper assesses implementation roadblocks by examining the real-time process, including modeling and planning, data acquisition, analysis, decision, field action, and process improvement.