bluuebunny/crossref_metadata_2025 huggingface dataset:
Downhole Pressure Uncertainties Related to Deep Wells Drilling are Safely and Precisely Ascertained using Automated MPD Technology
Authors: Vieira P.. , Torres F.. , Qamar R. A. , Marin G. E.
Published: February 2012

Drilling Deep Wells leads to face harsh operational conditions such as HP/HT, wellbore stability issues, narrow influx/losses windows which consequently make these prospects costly inefficient and highly risky safety wise, especially if the case is an exploratory well. Managed Pressure Drilling (MPD) is an enhancement of the primary well control provided by the utilization of a closed and pressurizable circulating system for the drilling fluids (mud), this enables drilling with precise management of the wellbore pressure profile, aiming to optimize drilling processes by decreasing nonproductive time (NPT), mitigating drilling hazards and to enable the drilling of otherwise technically or economically un-drillable and high-complexity prospects, offering a considerable amount of tangible benefits. Because MPD addresses NPT, the technology is of greatest potential benefit to deep wells drilling programs where cost of dealing with troublesome zones while drilling is much higher.

Several wells ranking from appraisal to wildcat exploratory with considerable pore pressure unknowns, coupled with narrow pore-fracture drilling window characteristic of HPHT conditions have been already drilled under the MPD technology in the MENA region. MPD was able to minimize the problems faced on previous wells conventionally drilled, by enabling various techniques which include the use of pressure build up analysis to quantify formation pressures, the application of dynamic flow checks, dynamic formation strength limits, and the application of constant bottom hole pressure during dynamic (pumps-on) and static (pumps-off) drilling fluid conditions. There are different providers at diverse levels of complexity that approach MPD systems. The system mostly selected by the operators to drill deep wells consists of an automated surface choke control system based on the mass balance monitoring principle and Rotating Control Device (RCD). The advantages of an automated MPD system are related to a quick reaction to the expected drilling problems and formations pressures uncertainties, all linked with the drilling process of an exploratory deep well. Drilling-related issues such as excessive mud cost, slow rate of penetration (ROP), wellbore ballooning/breathing, kick-detection limitations, difficulty in avoiding gross overbalance conditions, differentially stuck pipe, twist-offs, and resulting well-control issues contribute to the decision of applying the MPD technology. This presentation summarizes the application of MPD to address drilling hazards by drilling with more precise wellbore pressure management utilizing an automated MPD system based on flow balance monitoring, adding value to the conventional drilling practice.
Drilling Hazard Mitigation Technology Enables Conventionally Undrillable Prospects To be Drilled With Reduced Nonproductive Time and Increased Operational Safety: Application of Solid Expandable Liners and Managed Pressure Drilling in Algeria Nezla Field
Authors: Hamoudi I.. , Kartobi K.. , Vieira P.. , Saad M. A. , Torres F.. , Qutob H..
Published: February 2012

The Nezla Field is a faulted anticline that makes conventional drilling challenging due to the presence of fractured and high pressure formations in the Triassic and Ordovician groups, representing trouble zones that jeopardize well objectives, adding costs and operational risks to the drilling process. This adverse condition was observed in the offset wells drilled with problems related to wellbore instability, lost-circulation zones and over-pressured formations leading to kick/loss well control scenarios that endangered the drilling operations and incurred significant Non-Productive Time (NPT). A Drilling Hazard Mitigation (DHM) approach was implemented to offset the risks of both deviating from the well objective and drilling plan.

The constraint to drill the planned 12-1/4" section in the well was the unpredictability of the pore/fracture pressure in the transition zone between Tags and Sandy Tags formations, representing a high level operational risk. The most optimum and reliable solution to achieve the goal of drilling this zone without loss of hole size was to set 9-5/8" casing shallower than planned and then isolate the lower section of Tags formation (abnormally pressurized) with an Open Hole Expandable Liner. Drilling the next hole section through the low pressure formations to set the 7" casing shoe was to be resumed as per the original plan. This allowed the 6" reservoir hole section to be drilled under the Managed Pressure Drilling (MPD) mode.

The CBHP (MPD technique) was planned to drill the 6" section through the tectonically fractured Sandstone Hamra Quartzite maintaining the ECD within the drilling window limits initially defined by the predicted formation pressure and the average mud hydrostatic with which fluid losses were experienced in the offset wells. While drilling, these limits were ascertained within the range of 1.26 SG EMW – gas influx and 1.32 SG EMW – fluid losses. The CBHP drilling mode enabled to manage the ECD in between influxes and losses only adjusting the well head pressure to obtain instantaneous changes in the Bottom Hole Pressure while circulation was in progress. During the pumps-off periods, back pressure was applied on the MPD choke by pumping mud across the top of the well to compensate the Annular Friction Loss pressure. Once these limits were reached, drilling progressed with managing simultaneously small gas influxes and tolerable losses; then TD was called since the risk of simultaneous total losses and gas Influxes in the underlying Hamra fault was increasing.

This paper describes in detail the DHM technology implemented in this well and presents the successful application of such technique to enhance Nezla field exploitation. Lessons learnt and challenges encountered will be also discussed.
Modelling of Hydraulic Fracturing in a Weak Permeable Formation
Authors: Sarris E.. , Papanastasiou P..
Published: February 2012

We present numerical results of a propagating hydraulic fracture in weak rock formations. The results were obtained from a Finite Element Hydraulic Fracturing model which simulates all the involved non-linear and coupled processes. The fracture is driven by pumping of an incompressible viscous fluid with Newtonian rheology. The fracturing fluid leak-off in the host rock formation is also considered. For propagation criterion a cohesive-softening model is implemented in interface finite elements and the bulk rock deformation is modelled by Mohr-Coulomb yield criterion. The main objective of this research work is to determine the influence of the stress-field, pore pressure field and pumping parameters on rock plastic deformation and its implications on fracturing net-pressure and fracture dimensions. It has been previously shown that in weak formations plastic yielding and the associated rock dilation create shielding of the fracture tip and hence larger pressures are needed to propagate the fractures and the created fractures are shorter and wider. We extend these studies to investigate the influence of the pore pressure which has been previously ignored. We found that high anisotropic stress field and high initial pore-pressure fields increase the plastic yielding in a rock formation demanding higher net-pressures for propagating a fracture and the created fractures are shorter and wider. This non-linear analysis and results may explain the differences observed in net-pressures between field measurements and conventional model predictions. These findings are important in improving the numerical simulators of modelling hydraulic fracturing in particular for short fractures in weak formations for sand control applications. The results are also important to better prediction of vertical fracture growth and containment in shale-natural gas stimulations where there are serious environmental concerns on the risk of ground-water contamination.
Utilize Real-time MWD Data for Wellsite Job Optimization to Provide a New Level of Process Control in Well Intervention
Authors: Mohamed Omar
Published: February 2012

A new application for downhole data acquisition provides real-time wellbore intervention optimization via measurement-while-drilling (MWD)-based technologies to enhance pipe-conveyed wellbore intervention operations. This paper discusses the incremental challenges of conventional fishing methods that are addressed by using downhole data acquisition technology for ‘smart intervention’ service in the following:

Casing exits

Casing milling

Packer milling

Retrieving deepset plugs

Pulling gravel-pack packers

Wellbore cleanup

A smart intervention module is one solution that is run in the workover string as close to the wellbore intervention bottomhole assembly as possible. It provides its own power supply, telemetry system, and sensors, and data is sent from the module via mud pulse telemetry to the surface, where it is displayed clearly on a rig floor monitor.

Surface rig-up requires a pressure transducer on the stand pipe or pumps, cables from the transducer to a junction box and the processor, which is connected to two real-time laptops. The smart intervention engineers provide 24-hr coverage, and both the smart intervention module and the surface equipment are included in the services provided.

The smart intervention system gathers downhole measurements like weight on tool, torque, revolutions per minute, bending moment, vibrations, pressure, and temperature to provide a clearer picture of what is occurring at and around the wellbore intervention tools. The data is then transmitted to surface where accurate, real-time decisions and adjustments can be made to optimize downhole intervention operations.
Hydraulic Fracturing as Development Strategy in the Congo Onshore
Authors: Perfetto R.. , Martocchia F.. , Binda A.. , Itoua R.. , Tita G.. , Ceccarelli R. L. , Tealdi L.. , Cafarelli R..
Published: February 2012

The benefits of Hydraulic Fracturing (HF) are well recognized in the oil industry, even if in many world regions it is still seen as a remedial operation rather than a reservoir development strategy. The big part of worldwide HF operations, are performed extensively in the US and Canada, primarily for reservoir development purposes of tight gas fields. However during the last few years, the global trend has seen a change and HF is now encouraged for adding new reserves, aiding the development of low permeability marginal reservoirs and prolonging life of brown fields.

In Congo Onshore, HF is now a consolidated reality, with more than 70 frac jobs pumped. Good results have encouraged management to increase fracturing activity: nowadays HF is performed on all the infill wells that are drilled in the low permeability layers of the reservoir.

From the early stages of development only the layers with the higher permeability were produced, while the possibility to develop the low permeability layers was not considered, because of very poor or zero production results due to the application of conventional completion strategy.

Since HF is now performed as a standard practice on new wells, it has been reconsidered for the application on old wells completed in the low permeability layers.

The challenge encountered on these old wells, has been the presence of long perforated interval.

Rigless operations (such as sand plug) and work-over operations (such as cementing of old perforated interval and re-perforations) have been needed for fracturing in order to avoid fracture initiation issues like multiple fractures and early screenout.

This paper will show the lessons learned and the main results achieved during this campaign and it is particularly focused on operational and logistic aspects, offering a full operational overview to all Companies and Operators that intend to apply this technology on their assets, maximizing oil recovery.
Selection of Technology for Produced Water Treatment
Authors: Das Pares Chandra
Published: February 2012

Selected technology for Makeup (MU) and Produced Water (PW) Treatment of thermal facilities (Cyclic Steam Stimulation (CSS), Steam Flood (SF) and Steam Assisted Gravity Drain (SAGD) plays an important role in the CAPEX and OPEX of the plant. This paper summarizes merits and demerits of the available technologies for PW treatment and presents a case study to establish the best solution for the ongoing design of the commercial plant of Kuwait Oil Company (KOC) for its initial phase of operation. To meet the production target, the time for collecting design data for PW from the pilot is not available to select the proper technology for PW treatment. Due to lack of proper analysis of PW, a conservative approach was made to select the PW treatment technology by using the analysis of the formation water with high Total Dissolved Solid (TDS). For the high TDS the selected technology was Mechanical Vapour Compression (MVC) system, a unit with high CAPEX and OPEX and is totally a new technology for CSS and SF process. With the case study, the paper demonstrates that although the formation water is with high TDS but the amount of coupled PW per barrel of crude could be very low. Thus with CSS and SF process, the TDS content of the produced water could be reduced substantially and MVC may not be an option. Field data showed as the sufficient amount of MU water is available, the need for recycling PW can be deferred. The technology for PW treatment will be selected based on the initial operating data. The accepted proposal will help the project to select the appropriate technology based on proper data of the commercial plant and may lead to a practical and economic design.
Artificial Lift of Water in Gas Wells
Authors: Bugbee William Charles
Published: February 2012

Optimizing well production is the key to increasing profits. That's why a growing number of natural gas producers are using innovative technology to capture more gas and increase well life. Traditionally, several separate devices have been used to perform measurement and control tasks. Now, a single flow computer streamlines operations by measuring gas and, by providing pipeline and wellhead control. This paper will show the benefits of using a top of the line flow computer with well tested a proven algorithm to increase production and life of a well.

The principle of the plunger is basically the use of a free piston acting as a mechanical interface between the formation gas and the produced liquids, greatly increasing the well's lifting efficiency.

The successful operation of these systems is predicated on the assumption that the wells have no packer or have communication between the tubing and the casing at the bottom of the production string.
An Integrated Model for History Matching and Predicting Reservoir Performance of Gas Condensate Wells
Authors: Farid A. M. , El-Banbi A. H. , Abdelwaly A. A.
Published: February 2012

Depletion performance of gas condensate reservoirs is highly influenced by changes in fluid composition below the dew point. Long-term prediction of condensate gas reservoir behavior is therefore difficult due to the complexity of both composition variation and two-phase flow effects. In this paper, an integrated model was developed to simulate gas-condensate reservoir behavior. The model couples the compositional material balance or the generalized material balance equations for reservoir behavior, the two-phase pseudo integral pressure for near wellbore behavior, and outflow correlations for wellbore behavior.

An optimization algorithm was also used with the integrated model so it can be utilized in history matching mode to estimate original gas in-place, original oil in-place and productivity index parameters for gas condensate reservoirs. The model can be used to predict the production performance for variable tubing-head pressure and variable production rate. The model runs fast and requires minimum input.

The developed model was validated using different simulation cases generated with a commercial reservoir simulator for variant reservoir and well conditions. The results show a good agreement between the simulation cases and the integrated model. After validating the integrated model against the simulated cases, the model was used to analyze production data for a rich gas condensate field (initial CGR of 180 bbl/MMscf). Tubing head pressure data for four wells was used along with basic reservoir and production data to obtain original fluids in place and productivity indexes of the wells. The estimated parameters were then used to forecast the gas and condensate production above and below the dew point. The model is also capable to predict reservoir pressure and bottom-hole flowing and tubing head pressures and can account for completion changes when they occur.
Guidelines to Optimize CO2 EOR in Heterogeneous Reservoirs
Authors: Shehata Ahmed M. , El-Banbi Ahmed H. , Sayyouh M. Helmy
Published: February 2012

CO2 flooding in oil reservoirs to enhance oil recovery is successfully applied in many ongoing projects in the world. The bulk of industry research and field testing of CO2 has been directed towards miscible displacement. This method of using CO2 appears to have the greatest potential for recovery of oil that would not have been recovered using conventional production methods.

The main objectives of this paper are to investigate the most important reservoir and operational parameters in CO2 flooding and to provide guidelines to maximize CO2 injection performance for different levels of reservoir heterogeneity. Several compositional simulation models were generated using actual field data. For each model, reservoir heterogeneity was evaluated using Lorenz and Dykstra Parsons coefficients. The different compositional simulation models were setup to investigate the effects of key parameters such as injection rates, injection patterns, well spacing, injection scheme (Continuous CO2, WAG, and SWAG), WAG cycle length, vertical to horizontal permeability, and horizontal injection wells on the recovery factor and production of CO2 projects.

Those different heterogeneous models were used to simulate different scenarios over a wide range of both reservoir and operational parameters and provided a comprehensive data set to evaluate the CO2 flood effectiveness in a variety of conditions. More than 700 simulation runs were designed using Experimental Design techniques to test those parameters. Several correlations (proxy models) were also developed and blind tested to check their effectiveness in predicting the performance of combination of parameters that were not even tested. As a result of this work, it is possible to use experimental design to test the performance of CO2 injection. It can be performed with acceptable accuracy by performing a limited number of runs; hence, reducing the time, effort, and money.

It was observed that the use of different heterogeneous models resulted in different overall field performance. Our results also showed that implementing WAG and horizontal wells enhance the oil recovery significantly.
Increasing Propane Productivity by Changing the Operating Conditions without Adding any New Facilities
Authors: Riad Tamer Hamdy
Published: February 2012

Gasco operates two NGL plants located in Alexandria; Amerya LPG plant and Western Desert Gas Complex (WDGC). Recently, Gasco has started up a new project that integrates the two plants to maximize Ethane and Propane productivity.

The project design is based on adding new process facilities in Amerya plant to start producing C2+ that directed to WDGC, while a new train is added in WDGC to increase the feed gas capacity and maximize C2+ recovery by applying the Gas Subcooled Process (GSP) as Ethan mode of operation scheme.

This paper presents a study to increase the productivity of the two plants by using simulation software to help the decision making for what the optimum conditions should be applied in different modes of operation to increase the production.
Polymeric Solutions to High Gas Influx in an Oil Producing Well: A Field Experience
Authors: Okeke Chinyere , Mofunlewi Samuel , Bankole Abidemi , Agbogu George U.
Published: February 2012

Petroleum production engineering aims to maximize oil and gas production in a cost-effective manner. Wells in one reservoir can be considered oil, condensate and gas wells, depending on the producing gas-to-oil ratio. As the wells produce, this designation can change, for example as oil is produced and gas or water reaches the perforated interval and becomes dominant in the production stream. This type of change is often undesirable and requires intervention to restore preferred productivity.

This paper describes a gas-shutoff intervention operation in an oil-producing well. The well was initially completed in September 1974, but recently the two upper sets of perforation began to produce excessive gas. The operator wanted to cease producing from those perforations and instead produce only the lower (oil-producing) perforations.

After considering various gas-shutoff options, the operator chose to use a permanent polymeric gel for the operation. The gel is formulated with low-molecular-weight polymers, which penetrate into the matrix pore spaces for a complete shutoff squeeze treatment.

This paper will describe laboratory testing, field experiences, challenges and operational procedures to create a number of conclusions about lessons learned and best practices for polymeric gels in gas shutoff operations.
Overview of Polymer Flooding (EOR) in North Africa Fields – Elements of Designing a New Polymer/Surfactant Flood Offshore (Case Study)
Authors: Shehata Ahmed M. , Ghatas Ahmed , Kamel Mahmoud , Aly Ahmed , Hassan Ahmed
Published: February 2012

When petroleum reservoirs are depleted by primary recovery mechanisms only small fractions are produced (5-30%). Implementing a secondary recovery, water flooding, would still not produce all the recoverable oil present in the reservoir due to a poor sweep efficiency as the result of bypassed or upswept oil. Use of polymer flooding increases water viscosity which controls water mobility thus improving the sweep efficiency, thus increasing the recovery factor. Many successful polymer projects have increased recoveries of 3-10%.

This paper presents a case study to investigate the effectiveness of polymer and surfactant flood in Offshore Egyptian Field. This field is located in the Gulf of Suez, and the reservoir is sandstone formation with active water aquifer and has very high permeability in the order of few Darcies. The reservoir contains medium quality crude having viscosity of 17.5 - 24 cp with mobility ratio of 22 – 49 which makes it a good candidate for polymer flooding especially the reservoir has high residual oil saturation.

The objective of this paper is to present an extensive review of the polymer flooding literature and what constitutes a successful polymer flood project worldwide.

We performed a reservoir simulation study to investigate the effect of different parameter on the polymer flooding performance using a sector model of the field. Parameters such as polymer type, polymer solution viscosity, polymer slug size, and slug concentration will be studied to come with different scenarios for evaluation and optimization of the polymer flooding pilot. This will be a key to evaluate the polymer flooding technique in the early stage of oilfield development.

Results of this paper, will present the methodology needed to design a polymer and surfactant flooding project and it will provide the steps and data needed from the core lab (related to the rock qualities) and fluid lab to calibrate and have representative reservoir simulation sensitivity runs to optimize the design. This paper will focus on a case study from North Africa to implement offshore polymer flooding.
Methodology for 3-D Reservoir Modeling Leads to Retrieving the Complexity of Limited Drilled Wells and Improving Development Decision Making for a Clastic Gas Reservoir, Qawasim Formation, Onshore Nile Delta
Authors: Reda A.. , Hashem A.. , Darwish M.. , El Ghanam M..
Published: February 2012

The 3-D distribution of property data is a powerful tool for understanding the spatial distribution based on hard well data and trends. The primary goals for building a 3-D reservoir model is to maximize the value of data by incorporating all available information into a quantitative, digital representation, handling large amounts of data, providing consistent analysis in 3-D, giving direct numerical input to flow simulation and pore-volume calculation, testing and visualizing multiple geological interpretations, and assessing uncertainties.

Integration is required to build a realistic 3-D reservoir geological model, including geophysics, geology, core, wireline logs and production data, and the reservoir engineering model. It imperative to minimize the uncertainties associated with volume estimations coming from a limited number of drilled wells in the field, reservoir geometry and geological structures, inconsistency of petrophysical properties, and water contact location.

In the present study, only one well is drilled in a relatively large area, leading to complications and consistent population of facies and petrophysical properties controlled by well data that assumes the homogeneity of the entire area. The uncertainties in defining original hydrocarbons in place, recoverable reserves, reservoir flow, and communications between reservoir layers become too high to optimize field performance and future development plans. Advanced modeling scenarios are performed based on the possibility of facies changes across the field area, seismic-depth conversion tolerance, field geometry, and structure. A perfect 3-D static reservoir model resulted, which matched identically to the dynamic reservoir engineering model and production history.

This paper explores a new methodology for 3-D reservoir modeling for fields with a limited number of drilled wells for the better understanding of field volumetrics and dynamic behavior and improving the decision on how, and where, to develop the field to drill more wells.
Numerical Modeling of Counter-Current Spontaneous Imbibition during Underbalanced Drilling
Authors: Naseri Masoud , Sinayuc Caglar
Published: February 2012

Mud solid and filtrate invasion are the most common causes of formation damage during overbalanced drilling (OBD), which is a method of drilling in which the wellbore pressure remains greater than formation pressure. During the past ten years, underbalanced drilling operations (UBD), which can be defined as a drilling method in which the wellbore pressure is less than formation pressure, has been growing due to their applications such as prevention of lost circulation, reduction of filtration lost in naturally fractured and mature reservoirs.

It is very difficult to always maintain the underbalanced conditions in drilling and completion operations during bit changing and tripping operations. In these cases due to the non-existence of internal and external mud cake, there will be high amount of mud solid and filtrate invasion into the formation.

Besides these, the potential of formation damage still exist during UBD due to Counter-current Spontaneous Imbibition (COUCSI) process. In this case, for water-based muds the original water phase pressure in the reservoir is less than the irreducible water saturation. Therefore the capillary pressure and wettability characteristics of the formation can result in water invasion from the drilling fluid into the formation.

The main goal of this study is modeling of this process for a vertical and horizontal well in a conventional reservoir, which are being derilled using a water-based mud system in an underbalanced mode, investigating the effects of some factors such as amount of underbalanced pressure difference and exposure time. In addition, the amount of invaded water and invasion distance are discussed too. The numerical modeling and resulting governing system of partial differential equations, the descretized forms and initial and boundary conditions are presented.

Based on this numerical modeling, it is shown that for high capillary pressure values, the amount of water invasion increases. Moreover, for lower underbalanced differential pressure and higher exposure times, water invasion and invasion distance increases too.
A Riveting Review of Worldwide Industrial Geological Carbon Capture and Storage Projects with the Junction of CO2 Emissions in Algeria.
Authors: Deghmoum Abdelhakim , Baddari Kamel
Published: February 2012

The geological sequestration of CO2 is a relatively new technology that seems to have rapidly maturated in providing an effective process of capturing CO2 from industrial pollutant emissions and storing it securely in deep geological formations. Through this technology, the anthropogenic CO2 emissions can be reduced by 20% globally by 2050. Furthermore, it is expected that by the end of this century, more than 55% of CO2 emission can be captured and stored geologically. The compression, the transport and the injection of CO2 have been well used and controlled in the petroleum industry for many decades. However, CO2 capture process remains the weak point that should be overcome in order to make CCS economically feasible at industrial level. Moreover, no risk of leakage can occur at very long term in order to make CCS technology possible and generalized.

The objective of this review is to analyze and to compare briefly the quantification of CO2 emissions in Algeria and to illustrate, with different case studies, the worldwide geological CCS pilot projects, particularly, those applied at industrial scale. The review is an attempt to assess critically what has been done and to predict what is ahead in this domain.

Based on this review, the authors conclude that the global warming is the consequence of human egocentrism. CO2 should be considered as a valuable gas and not a waste, and CCS as a solution to global warming. Although there is negligible CO2 emission in Algeria, In Salah CCS project, built by BP-Statoil-Sonatrach consortium, is for demonstrating that pollution has no boundaries and every country is concerned by environmental issues. Thus, developing and developed countries should be urgently implicated in a serious and strong cooperation in the deployment of CCS technology before reaching irreversible global warming consequences.
A Generalized Model for Natural Flow of Gas in a Reservoir with Power Law Trends
Authors: Kummeneje Øyvind Steinset , Jelmert Tom Aage
Published: February 2012

All reservoirs cannot be described by conventional models. These are characterized by constant or piecewise constant rock properties. Sometimes a power law trend may be a better assumption. Power-law trends include but are not restricted to fractal reservoirs. A concept of fractal involves the additional assumption of self-similarity.

Fracture topology, changing flow area, and heterogeneities may also contribute to power-law dependency. We use fractal nomenclature to formulate the mathematical model. The solution methodology, however, is valid for any reservoir that may be characterized by power-law expressions.

We consider boundary dominated flow of pseudo-steady type. This simplifies the partial differential to an ordinary differential equation. An approximate inflow equation pwf vs. q, may be obtained by direct integration. The natural flow rate of a well may be obtained as the intersection of the fractal reservoir inflow performance relationship, IPR, and the vertical lift equation, VLF. The proposed technique is a generalization of a classical technique to plan and design wells in homogeneous reservoirs.

Application of the proposed methodology may improve production forecasting and aid design of wells in drainage areas where the fluid follows a complex flow path towards the well. The current formulation applies to one phase flow of a real gas. The model accommodates rate dependent skin. We investigate the sensitivity of the natural flow rate to changes in reservoir and well parameters. The objective is to shed light on possible benefits of projects to accelerate and improve gas recovery. We investigate the sensitivity to skin removal, infill drilling and change of well head pressures.
Tracking Subsea Gas Wells performance without Periodic Production Testing on Test Separator
Authors: Selim I. El-S. , Shokir E. M.
Published: February 2012

Tracking well performance is essential in understanding reservoir behaviour, reservoir management and matching reservoir simulation models with historical data. It results in forecasting reservoir performance accurately. Also, tracking wells performance for multi-fields company with multi joint ventures is important for production allocation for fair company revenue distribution. Regular well testing is required for tracking well performance but in a subsea environment using traditional testing tools such as test separators and slick line downhole gauges to measure production rates and bottom hole pressures, would cost millions of dollars. So these types of tools don't suit a subsea environment therefor other tools to track subsea wells performance are required.

This paper presents tools to tracking subsea wells performance without test separator and by using interventionless tools such as; permanent down hole gauges, venturi and wet gas meter (WGM) with identifying uncertainty in rates measurements with these tools and focusing on measured rate validity techniques by using quality checking (QC) tools such as: a) tracking field production allocation factor b) Sensitivity on measured rates by Integrated asset model (IAM), c) using shifted well inflow performance relationship (IPR) and d)Comparing pressure drops along flow paths with initialized selected well flow correlations.

Successful applying of QC techniques on monitored rate of subsea wells for gas field Z allows for identifications of errors in rates measurements and predicting the actual well rate. These assist in simulation history matching and fair distribution to company revenues between JV partners companies.
New Methods to Predict Inflow Performance of Multiply Fractured Horizontal Wells under Two-Phase Condition and Optimize Number of Fracture Stages
Authors: Zhang He , Han Guoqing , Houeto Fabien , Lessard Rodney , Wang Wenhao , Li Jun
Published: February 2012

A new method is presented to calculate the total inflow and associated productivity index (PI) under two-phase conditions by a sum of contributions from matrix and N multiple fractures using semi-analytical methods. Maximizing the net Present present value (NPV), the new inflow performance relationship (IPR) models can determine the optimal fracture stage number. Furthermore, the deliverable PI is used as an input to a network model to calculate the operating rate, taking into account the network constraints such as the node pressure, allowed flowrate, or choke in place. Through this analysis, one may determine that the horizontal well of interest may not flow at the maximum PI―it suggests that the network constraints dissipate the contribution from m stage(s) fractures. The number of fracture stages is then reset to (N–m), the IPR model is rerun, and an updated PI is imported into the network model. This process is iterated until the final optimization is achieved.

This method can quickly optimize the number of fracture stages for horizontal wells under two-phase solution-gas conditions, assisting operating companies in planning field development.
A Grid-Free Method to Enhance Reservoir-Well Coupling
Authors: Li Jun , Wang Wenhao , Zhang He , Houeto Fabien
Published: February 2012

Reservoir and well simulations are often coupled to allow more realistic production forecasts. Proxy functions are typically generated by a well simulator as a preprocessing step to characterize the response from the production system when the reservoir condition changes. With proxy functions, a reservoir simulator can take into account the response from the well without simultaneously performing the well simulation, which can be time prohibitive. This indirect coupling is effective only when the interpolated values from the proxy function closely match the results from the surface simulation. Typical implementations of proxy functions require characterizations at each grid point, which can be expensive to compute for a fine grid. Due to the intrinsic curvilinearity of well performance curves, the accuracy of proxy functions highly depends on the number of sampling points.

In this paper, we discuss a new method for generating proxy functions that improves accuracy without sacrificing performance. We propose to use kriging to enhance the efficiency and accuracy of characterization of the surface simulation. Kriging interpolation provides a grid-free representation of the proxy function, which allows the flexibility of choosing the sampling points for well simulations. We propose to put more sampling points where the rate of change of the proxy function is relatively large.

Our numerical results show that the grid-free method reduces the interpolation error by over 40%, without increasing the number of sampling points. Furthermore, with a comparable level of accuracy, simulation time for generating the proxy function is reduced by 50%.
Effect of Presence of Crude Oil on the Performance of Emulsified Acids
Authors: Sayed M. A. , Assem A. I. , Nasr-El-Din H. A.
Published: February 2012

Acid treatment in carbonate reservoirs targets to restore or to stimulate the near-well area. Emulsified acid can be used in matrix acidizing and acid fracturing treatments. The delayed nature of emulsified acid is useful in creating deep wormhole and etched fracture surfaces. Almost all coreflood work done before was performed on cores fully saturated with water. Therefore, the main objective of the present work is to study the effect of presence of crude oil in the formation on the performance of emulsified acid in stimulating carbonate formation.

A coreflood study was conducted using high permeability Indiana limestone cores which have dimensions of 1.5" diameter and 6" long. The effect of the presence of crude oil inside the core on the volume of acid to achieve acid breakthrough was studied. Also, the size, numbers and distribution of the resulted wormholes as a function of the core fluid content was studied through the analysis of the CT images on the core after injection of emulsified acid. Also, the effect of the acid injection rate on these parameters was studied. Cores that are fully saturated with water and cores saturated with crude oil and water were used to study the performance of emulsified acids.

From the coreflood study, there was no optimum injection rate for an emulsified acid system when it was tested against high permeability Indiana limestone cores fully saturated with water. For high permeability Indiana limestone cores, emulsified acid enhanced the rock permeability when the acid injected at high rates. For cores saturated with crude oil and water, there was no clear relationship between volumes of emulsified acid required to achieve breakthrough and emulsified acid injection rate. Also, volumes to emulsified acid to achieve breakthrough in cores saturated with crude oil and water are greater, compared to acid volumes required to achieve breakthrough in cores fully saturated with water. Emulsified acid system is effective in stimulating limestone cores, at different acid injection rates and at high temperatures, even the cores were saturated with water or saturated with crude oil and water.
Narrow Margin Drilling and Operational Geosciences in Egypt and Syria
Authors: Tichelaar Bart W. , Salem Hisham F. , Amin Sandy A. , Shafik Ramy M.
Published: February 2012

The ability to drill exploration objectives safely and efficiently is controlled by knowledge of the available drilling margin. We present an application of operational geosciences for two recent exploration wells in Egypt and Syria where pore fluid pressure and fracture pressure models were built pre-drill to enable well design. While drilling the well, these models were updated in real-time (24/7) to make the right operational decisions. In addition, before drilling the more challenging well sections, learnings from shallower sections in the well were used to prepare a look-ahead assessment of the available drilling margin to select a strategy to drill the next section.

The two wells have in common that the presence of a narrow drilling margin was recognized early in the exploration phase such that proper data analysis could be completed pre-drill for the entire planned well trajectory. Furthermore, options for real-time data acquisition were investigated early such the right geoscience data could be acquired and interpreted during drilling for operational support.

Engineering, geosciences and communication form equally important components of narrow margin well execution. Real-time analysis of logging while drilling data, mud logging data and hydraulics data was used, as well as the intelligent deployment of managed pressure drilling technology, to make decisions such as adjustment of the drilling mud and selection of section depth (TD). A Communications Protocol was followed to assure that critical anomalies in the predicted drilling margin were efficiently communicated to the Drilling Supervisor for immediate operational response.
Integrated Production Analysis before Implementation Pilot Water Flooding and Surveillance & Monitoring during Pilot Water flooding on Rantau Structure Zone 600
Authors: Suarsana I Putu , Badril Areza
Published: February 2012

Rantau Field, located in the working area of PT. Pertamina EP, is considered as matured field. The field is located in North Sumatra, Indonesia. This field started producing in primary stage in 1930, and the secondary stage had been started in 1984 by injection of water. The water source comes from sea water with a salinity of 26000-33000 ppm. Since the injection of water quality is not good, then it had been damaged the injection wells, and it would automatically have an effect on the production wells. The oil production then started to decline.

Pertamina EP EOR management team tries to increase the oil production back by implement re-secondary recovery process. The work started from field screening, study G&G, production analysis, preparing facility production, and follow up with a pattern pilot water flooding, and finally full scale project. Pilot water flooding kick off at layer Z-600 conducted in January 2010, Pertamina EP implemented a pilot water flooding in layer Z-600 block of C1 and C2 and managed to increase oil production from two wells (0 BOPD to 400-500 BOPD) and the reservoir pressure (from 155 Psi to 222.5 Psi in 3-month period conducted a pilot water flooding). With the success of pilot water flooding on the blocks C1 and C2, Pertamina EP will continue to full scale water flooding phases are planned to be carried out gradually in block A1 and A2. In addition to conducting secondary recovery, Pertamina EP will also plan for tertiary recovery phase for blocks/compartments that have been carried out secondary recovery activities. The production analysis is very important role in injection design, the scope include production and injection performance analysis, connectivity between injector and producer, pattern design and surveillance and monitoring.
Canadian Occupational Performance Measure: Impact of Blinded Parent-Proxy Ratings on Outcome
Authors: Wallen Margaret A. , Ziviani Jenny M.
Published: February 2012

Background. There is potential for unintended effects on intervention outcome when using the Canadian Occupational Performance Measure (COPM) in intervention studies.

Purpose. To determine the effect of blinded parent-proxy ratings of the COPM on outcomes at later endpoints.

Methods. Data were drawn from a randomized trial of 50 children with hemiplegic cerebral palsy aged 19 months to seven years. Outcomes were measured at baseline, post-intervention, and six months. Parents of 36 children were randomly allocated to complete six-month COPM proxy ratings blinded or unblinded to previous ratings. A group of 32 parents rated the six-month COPM blinded and then re-rated it after access to previous ratings.

Findings. There was no statistically significant difference in ratings between those completing the COPM blinded compared to unblinded.

Implications. The COPM should continue to be rated blinded at post-intervention endpoints in the absence of further research to the contrary.
Problem-Solving Strategies of Women Undergoing Chemotherapy for Breast Cancer
Authors: Lyons Kathleen D. , Erickson Kelly S. , Hegel Mark T.
Published: February 2012

Background. Many women undergoing chemotherapy for breast cancer experience side effects that make it difficult to perform daily occupations.

Purpose. To summarize the types of challenges, goals, and adaptive strategies identified by women with stage 1–3 breast cancer participating in a pilot study of Problem-solving Treatment-Occupational Therapy (PST-OT).

Methods. Content analysis of 80 PST-OT sessions.

Findings. Women addressed 11 types of challenging activities, with exercise and instrumental activities of daily living (IADL) being the most common. Most women set a goal to adapt a current activity, but also set goals to find a new activity, plan the steps of a current activity, or gather information about a possible activity change in the future. The adaptive strategies generated by the women were grouped into five types. Most often they found ways to add a new step to an activity, but they also brainstormed about when, how, where, and with whom they could do activities.
“Support for Everyone”: Experiences of Occupational Therapists Delivering a New Model of School-Based Service
Authors: Campbell Wenonah N. , Missiuna Cheryl A. , Rivard Lisa M. , Pollock Nancy A.
Published: February 2012

Background. Occupational therapists working in school health have recognized the need to move away from a one-to-one direct service delivery model towards a more collaborative, classroom-based approach. Partnering for Change (P4C) is an innovative service delivery model that may enhance school-based collaborative care.

Purpose. To capture the experiences of occupational therapists implementing P4C and to elicit their perspectives about how this model differs from the direct service approach.

Methods. Semi-structured, face-to-face interviews were conducted with seven therapists who had delivered P4C in 10 Ontario schools. Thematic analysis was utilized with themes verified through member checking.

Findings. Five themes (a year of growth, becoming a community, the key ingredients of P4C, a balancing act, and providing services that make an impact) reflected therapists' personal and professional growth, aspects of the model they believed were key, challenges they encountered, and the impact they felt they had made.

Implications. Partnering for Change has the potential to transform school-based occupational therapy and overcome existing barriers to collaboration. This model also may better address the needs of children with motor coordination difficulties.
Effect of fill-factor on the Talbot effect of diffraction gratings
Authors: Salgado-Remacha Francisco Javier , Sanchez-Brea Luis Miguel , Bernabeu Eusebio
Published: February 2012

We analyze the effect of the fill factor of binary diffraction gratings on the Talbot effect under a scalar approach. We show that the location of the best-visibility planes changes with the configuration parameters of the grating, that is, the amplitude and phase modulation and the fill factor. Moreover, different intensity patterns and contrast shapes can be obtained when different configurations are used. Analytical expressions describing the contrast of the diffracted field are obtained, that agree with numerical simulations.