bluuebunny/crossref_metadata_2025 huggingface dataset:
Stability Analysis of Pipe with Connectors in Horizontal Wells
Authors: Gao Guohua , Di Qinfeng , Miska Stefan , Wang Wenchang
Published: October 2011

Except for coiled tubing, most tubular goods used for down-hole operations such as drilling pipe and sucker rod have connectors. Since a connector and the pipe-body have different outer radius, the deformation and buckling behavior of a pipe with connectors constrained in a wellbore are much more complicated. However, most buckling models were established by neglecting the existence and effects of connectors.

In this paper, buckling equations of a pipe with connectors in horizontal wells were derived with application of elastic beam theory. The axis of an unbuckled pipe is a 2-D curve in the vertical plane, and has three configurations: no contact, point contact and wrap contact. We derived the two critical distances between connectors, Lc1 and Lc2, beyond which a pipe changes its configuration from one to another. The authors proposed an algorithm to determine the critical force (Fcrs) of buckling by numerically solving the buckling equations using the 4th order Ronge-Kuta method.

Both the distance between two adjacent connectors (Lc) and the radius difference between a connector and the pipe-body (Δrc) have significant impact on the critical force, in addition to net clearance between a pipe and wellbore (r0), bending stiffness (EI) and weight per unit length (w) of pipe. When Lc is small, radial deflection is negligible. Fcrs increases as Δrc increases. However, when Lc is close to Lc1, effects of radial displacement become significant, and Fc decreases dramatically as Δrc increases. Fcrs decreases as Lc increases when Lc< Lc1, and it reaches its minimum at Lc=Lc1. When Lc> Lc1, Fcrs fluctuates as Lc increases. Some curves of Lc1, Lc2 and Fcrs, all in dimensionless forms, were calculated and presented in this paper for practical applications.

Our numerical results show that the critical force may reduce 20-60% for commonly used drill pipes and sucker rods with centralizers, which indicates that a pipe string designed without considering the effects of connectors may be risky. The results presented in this paper may provide some practical guidance for optimal design of centralizers for sucker rod strings, or may avoid some risks due to improper design of drilling pipe strings.
Quantitative Integration of Flow Simulation and 4D Multi-Component Seismic in a CO2 WAG EOR Project
Authors: Heris A. E. , Wandler A. , Kazemi H. , Davis T. L.
Published: October 2011

In management of mature oil fields for enhanced oil recovery, 4D seismic imaging plays a very important role. Previously, we published the qualitative results of integrating flow simulation with time-lapse multi-component seismic data for a CO2 EOR project in the thin valley-fill Morrow formation at Postle Field. In this paper, we will present our quantitative approach and results from integrating flow simulation with time-lapse seismic.

Three seismic surveys have been acquired at Postle Field to monitor the ongoing CO2 flood. Since presentation of the previous paper, additional seismic and production data has become available which has influenced both the history match of the reservoir flow model and seismic interpretation. Gassmann's fluid substitution method was used to relate the flow simulation results with time-lapse seismic attributes. In addition, a sensitivity analysis was performed using a conceptual model to investigate the effect of various reservoir dynamic parameters on seismic response.

Flow simulation and rock physics modeling show that production and injection in the reservoir causes saturation and pressure changes, which affect acoustic and elastic properties of the reservoir. Acoustic impedance calculated from the simulation model was compared to the corresponding results from seismic data. The magnitude of changes of acoustic impedance calculated from the flow simulation is similar in range to that from seismic inversion. The effect of fluid saturation change in the reservoir, particularly CO2 saturation, is greater than the effect of pressure change. Conceptual modeling indicates that the sensitivity of seismic attributes to changes in CO2 saturation and water saturation is weak and may be difficult to detect seismically. On the other hand, to have a relatively big change in acoustic impedance, a big change in pressure is needed.

Our research results demonstrate that for a credible dynamic reservoir characterization, an integration of flow simulation and 4D seismic is required which, in turn, could be a viable method to guide field operations. However, this process is challenging in thin reservoirs undergoing CO2 WAG injection.
Geographic Response Strategy "An Integrated System for Effective Spill Response"
Authors: Ayu Sito Mirah , Rusjanto Juli , Sarwanto Puguh , Hidayatullah Hidayatullah , Prasetyo Romy Irvan
Published: October 2011

A continuous improvement in dealing with hydrocarbon spill in Mahakam Delta is important due to the rapid change and more stakeholders in the area. Geographic Response Strategy (GRS) can answer the challenge to help spill responder in decision making by providing integrated essential information in one tool.

During emergency response operations, the available information may be highly uncertain, especially the initial information in the early stages of the emergency situation. This condition requires the emergency response team to ascertain what is actually known about the emergency situation, assess and select the best strategy to respond to the situation as soon and as effectively as possible. Appropriate strategy is very essential in order to minimize the overall consequences on people, environment, asset and company reputation.

GRS ensures that Main Emergency Control Cell (ECC), Site ECC and field responder are in the same perspective during spill response. Main ECC and Site ECC able to access information and strategy guideline in the GRS through intranet while field responder able to perform response strategy accurately using Field Responder Map.

Essential information which are integrated in the GRS covering Total E&P Indonesie facilities, pipeline inventory, emergency shutdown valve (ESDV) location, emergency equipment at site, sensitive area location, hazard location, spill response guideline, hydrodynamic 3D modeling, and automatic vessel tracking system. GRS implementation offer solution for making decision within tight timeline. It can help in prioritizing action; protect sensitive area, which at the end will reduce safety risk, environmental impact and cost associated with the impact.
From the Classroom to the Field: Learning Transfer Strategies
Authors: Wakefield Sarah , Murdock Patty , Pigusch Katrina
Published: October 2011

"What does this have to do with the real world?" These words sometimes thought by students in the academic world should never go unanswered by technical training classes in the corporate world. In the competitive business environment of today, at a time when mistakes on the job cost a premium, the industry needs technical training that effectively makes the leap from the classroom to the job. Valid strategies for classroom learning transfer do exist. Classroom training must be made relevant to the workplace. This can be accomplished, for example, by providing context, building new information based upon old information using realistic exercises and simulations, applying memory techniques and referring to specific questioning techniques that relate classroom information to the job. In this paper, the research behind learning transfer as well as specific technical oilfield examples will be discussed. This information is relevant to industry professionals who wish to facilitate an effective learning transfer from the classroom to the field.
Heat Transfer Applications for the Stimulated Reservoir Volume
Authors: Thoram Srikanth , Ehlig-Economides Christine
Published: October 2011

Multistage hydraulic fracturing of horizontal wells enables creation of a Stimulated Reservoir Volume (SRV). An idealization of the SRV for shale gas production is a rectangle of length equal to horizontal well length and width equal to twice the half length of the created hydraulic fractures. This paper discusses the use of an analogous SRV design for two novel thermal applications.

The first application considers using the SRV of a shale gas well, after the gas production rate drops below the economic limit, for low grade geothermal heat extraction. Cold water is pumped into the fracture network through one horizontal well drilled at the fracture tips. The water is heated by contact with the hot rock, and then recovered through a second horizontal well drilled at the other end of the fracture network. The basis of this concept is to use the already created stimulated reservoir volume for heat transfer purposes. Technical and economic feasibility of applying this technique to Haynesville Shale are evaluated.

The second application considers using a similarly created SRV for producing oil from oil shale. Thermal decomposition of kerogen to oil and gas requires heating the oil shale to 700°F. We propose to inject high quality saturated steam generated using a small scale nuclear plant for heating the formation to the necessary temperature. Using the same flow geometry as in the previous case, produced water would be reheated and reinjected in a closed cycle. The energy required for steam heating is compared to other approaches in the literature.

Analytical and numerical models are developed to evaluate the number, dimensions, and spacing of fractures sufficient to achieve heat transfer in a reasonable length of time for each of these applications.
Decreasing Water Invasion into Atoka Shale Using Non-modified Silica Nanoparticles
Authors: Cai Jihua , Chenevert Martin E. , Sharma Mukul M. , Friedheim Jim
Published: October 2011

Fluid penetration from water-based muds into shale formations results in swelling and subsequent wellbore instability. Particles in conventional drilling fluids are too large to seal the nano-sized pore throats of shales and to build an effective mud cake on shale surface and reduce fluid invasion. This paper presents laboratory data showing the positive impact of adding commercially available, inexpensive, non-modified silica nanoparticles (particle sizes vary from 5 nm to 22 nm) to water-based drilling muds and their effect on water invasion into shale.

Six brands of commercial and non-modified nanoparticles (NP) were tested and screened by running a three-step pressure penetration test (brine - base mud - NP mud). Two types of common water-based muds (a bentonite mud and a low solids mud, or LSM) in contact with Atoka shale were studied with and without the addition of 10 wt% nanoparticles. We found that a large reduction in shale permeability was observed when using the muds to which the non-modified NPs had been added. For the bentonite muds, the permeability of Atoka shale decreased from 57.7% to 99.3% and for the low solid muds, the permeability of Atoka shale decreased from 45.67% to 87.63%. Higher plastic viscosity (PV), lower yield point (YP) and fluid loss (FL) of the NP muds compared with base muds were also observed by the addition of NPs. We also found that nanoparticles with size varying from 7 nm to 15 nm are more effective plugging agents than larger nanoparticles for the Atoka shale.

This study shows for the first time that it is possible to formulate water based muds using inexpensive non-modified and commercially available silica nanoparticles and that these muds significantly reduce the invasion of water into the shale. The addition of silica nanoparticles to water based muds may offer a powerful and economical solution when dealing with wellbore stability problems in troublesome shale formations.
Capacitance Resistive Model Application to Optimize Waterflood in a West Texas Field
Authors: Nguyen Anh P. , Lasdon Leon S. , Lake Larry W. , Edgar Thomas F.
Published: October 2011

This paper describes the application of capacitance resistive modeling (CRM) to 99 wells in a waterflooded field in the Permian Basin of West Texas. CRM is a quantitative technique based on material balance that requires only injection, production rates and well coordinates to identify and quantify interwell connectivity in a waterflood. The study uses CRM results to optimize oil production by reallocating water injection and then assesses the resulting improvement by analyzing field data after water injection has been rescheduled. This first field implementation of CRM theory shows that the oil production rate has increased 45 bbl/day and the cumulative incremental oil production in the first year is 5, 372 bbls, equivalent to $402, 900 at $75/bbl.

This work serves as a demonstration of how to apply and analyze CRM results. Before optimizing injection, interwell connectivities were established by fitting CRM over an appropriate fitting window selected using field events. The forecasting ability of the model was examined by fitting part of the historical data and then using the fitted model to forecast the remainder of the historical data. CRM interwell connectivities were used to optimize future production for the next five years by changing water injection rates. The optimized injection rates were applied for one year and the resulting production rates were analyzed.

The oil production rates increase after injection rates were rescheduled according to the CRM optimization. This first field test of CRM technology has demonstrated that CRM has the advantages of short computation time and of using readily available field data, and disadvantages of sensitivity to reservoir events and data errors. The connectivities are consistent with field geological knowledge. CRM can be used to improve oil production with little additional cost.

The case study shows that CRM is a simple yet powerful tool for engineers in planning and monitoring waterflood. The work increases confidence in the technique by demonstrating improvements made by using CRM in a practical context, and identifying shortcomings of the technique. CRM should be applied with knowledge of the field geology and history to understand the results and use them to enhance waterflood performance.
Nonlinear Formulation Based on EoS-free Method for Compositional Flow Simulation
Authors: Zaydullin R. , Voskov D. V. , Tchelepi H. A.
Published: October 2011

Compositional simulation is necessary for the modeling of complex EOR processes. For accurate simulation of compositional processes, we need to couple solution of nonlinear conservation laws for multicomponent multiphase flow and transport, with a system of equations describing the phase behavior of the mixture at q thermodynamic equilibrium. The complexity of the problem requires extensive computations and consumes significant CPU time. We present an efficient and robust framework for the computation of the thermodynamic phase behavior associated with multi-component multiphase flow in porous media. The method is based on adaptive interpolation of supporting tie-lines in compositional space. For the parameterization of full solution of a complex compositional problem we need only a limited number of supporting tie-lines in compositional space. We use a special approach for the adaptive construction of these tie-lines, depending on predefined precision. The parameterized tie-lines are triangulated using Delaunay tessellation, and natural-neighbor interpolation technique is used inside the supporting simplex. The computation of phase behavior for the composition simulation then becomes an iteration-free procedure and does not require any EoS computations. Based on this method, we developed a new nonlinear formulation for fully-implicit compositional simulation for both immiscible and miscible displacement. The treatment of nonlinearities, associated with complex thermodynamic behavior of the fluid, is based on the new set of unknowns - tie-line parameters, which allows for efficient representation of the subcritical region. For the supercritical region we use the standard compositional set of variables that based on the overall composition. A new criterion is proposed for the identification of changes between sub- and super-critical regions, and the robust variable substitution is applied during the simulation process. The efficiency and accuracy of the method is demonstrated for several multi-dimensional compositional problems of practical interest. For the tested problems, the proposed method significantly reduces the computational cost of the thermodynamic calculation compared with the standard EoS-based approach. Moreover, the method shows substantially better nonlinear convergence in the case of near-miscible gas injection simulation.
Inflow Performance Identification and Zonal Rate Allocation from Commingled Production Tests in Intelligent Wells—Offshore West Africa
Authors: Saputelli Luigi , Oluwole Omole , Lissanon Janvier , Gonzalez Fabio , Chacon Alejandro , Sun Kai
Published: October 2011

The main objective of a production well test is to assist in the identification of reservoir and well parameters needed for regulatory accounting, well surveillance, and asset management purposes. Interpreted information is used to drive decisions on production enhancement, operations optimization, and field-development plans. However, uncertain results may occur when wells are produced from multiple reservoirs. Currently, the industry approach is to allocate well and reservoir parameters based on known petrophysical data, offset well information, and zonal well tests. When possible, testing by difference is commonly performed to control one or more zones; however, this process may result in significant production losses with poor concluding results, especially when zonal interference is vital to a well's operating point (e.g., intelligent wells in a waterflood field).

A methodology was developed to consistently identify reservoir and well-performance parameters from wells produced under commingle conditions from multiple reservoir zones by leveraging available real-time data. This methodology was successfully applied in a field located in offshore West Africa, a waterflooded field with nine intelligent wells. The methodology integrates surface well-test rates, pressures, and downhole triple-gauge data. Collected data is validated via a rigorous history calibration process of an integrated production model consisting of an analytical reservoir, well, downhole and surface chokes, and pipeline models. The calculated parameters (e.g., zonal rates, productivity index, reservoir pressure, gasoil ratio, and water cut) are the result of an error minimization between calculated variables and measured field data.

This paper presents applications of this methodology for two production tests of a single dry-tree well with individually controlled reservoir zones. Benefits of the above application include a 90% reduction of the time required to perform a similar analysis, reduced uncertainty in rate allocation and reservoir parameters, and better understanding of the likely production from every reservoir zone. Because well and reservoir parameters are allocated to individual layers, the resulting rate allocation satisfies all sensor data and physical models, and therefore the uncertainty of the allocation is reduced. In addition, the application provides the basis for rate allocation to multiple zones in real time when well tests are not available.
Barite Sag Occurrence and Resolution during Angolan Completion Operations
Authors: McNerlin B. , Oakey N.
Published: October 2011

Barite sag or solids sag is a phenomenon where by a fluid sheared at low flowrate does not have the viscous properties necessary to keep the solids within it in suspension. The solids can subsequently fall out of suspension, which can lead to an undesireable build-up of solids in the wellbore or density contrasts within the fluid. During drilling activities solids sag can be avoided by increasing flow rates, rotating the drill pipe, and viscosifying the drilling mud. However, during completions operations, none of these mitigating practices may be possible due to limitations of the setting tools or installed equipment deployed into the well. For open hole completions where sand screens are deployed in highly conditioned muds, solids sag has the potential to be a serious issue, and needs to be avoided. Since 2009, there have been at least four incidents of solids sag occurring during completions operations in the Greater Plutonio development in deepwater Angola, at relatively low fluid densities. Each event manifested itself in a different way, and caused different problems during and after installation of the completion equipment.

This paper presents case studies of the solids sag events that occurred during completions operations, and how they either affected installation operations or well productivity. It then describes the work done to eliminate the solids sag, including fluids testing performed to identify it, changes to operational practices, short term modifications to mud rheology, and long term mud solutions.
Preemptive Scale Management: Treating with Scale Inhibitor While Frac Packing a Well
Authors: Marquez M. , Schafer L. , Norman W. D.
Published: October 2011

Fracpacks have become the completion of choice for deepwater wells due to concerns over loss of productivity associated with fines and sand production, limited rig availability and high intervention / sidetracking costs. Many deepwater reservoirs also require seawater injection in order to maintain reservoir pressure and increase the ultimate recovery of hydrocarbon reserves. This practice can significantly increase the potential for scaling, particularly the deposition of barium sulphate (BaSO4) scale in reservoirs with high barium concentrations. Mechanical removal of sulphate scale at the reservoir level and / or from a damaged fracpack is not feasible. Chemical dissolution is not always practical, particularly in cases of high scale buildup. In these circumstances, little can be done to restore loss production except for pulling the completion or sidetracking the well. In either case, the consequences of sulphate scale build-up can be detrimental to the economics of the project, especially for high rate producer wells. For these reasons, preemptive scale management, most often in the form of scale squeezes, is a standard operating practice in high value wells susceptible to scaling. Deployment of a scale inhibitor concurrently with well completion operations is very attractive in that it delays the onset of scaling while providing a means for scale inhibition monitoring from the start of production. This not only provides adequate protection in case of early water breakthrough, but it also provides warning to plan and schedule routine well interventions, efficient utilization of resources (rig availability, workover crews, etc.), and better reservoir management.

The addition of a phosphonate scale inhibitor into the pre-frac acid and overflush brine stages preceeding the frac operation was previously discussed in SPE 127768. As an extension of the previous work, a liquid pentaphosphonate scale inhibitor has been successfully incorporated into a seawater-based, borate-crosslinked frac fluid for fracpack operations in deepwater environments. Many challenges, including complex shear and temperature profiles, as well as potential incompatibilities arising from the interaction between the SI, crosslining agent / buffer package, and seawater were overcome by adjustments made to the crosslinking package, polymer loading, and fluid pH. The rigorous laboratory testing that led to the development of optimized fluid formulations, the assessment of scale inhibitor efficacy and formation damage potential is described herein.
Incorporating Geomechanics into the Decline-Curve Analysis of Naturally Fractured Reservoirs
Authors: Jabbari Hadi , Zeng Zhengwen , Ostadhassan Mehdi
Published: October 2011

This paper presents a new production decline model for naturally fractured reservoirs (NFRs), which takes the geomechanical behavior of the formation into account. Since the pressure transient data can be costly and may not be available for most wells, decline curve analysis that uses readily available well production data would be beneficial. Decline-curve analysis methods, in a variety of forms, have been used in the industry to analyze production data and forecast reserves for many years. However, the impact of geomechanics is not considered in the existing models.

As reservoir pressure decreases due to production, fracture aperture can be influenced by both the matrix elasticity and fracture compressibility. This will result in permeability change in the fracture system. To include the impact of the geomechanical properties, a model is derived to understand how pressure change can affect the fracture permeability and behavior of NFRs. It is important to find out this relation since the fractures would close, or at least diminish, after a long period of producing time.

The original model of dual-porosity developed by Warren and Root is extended to include the effect of geomechanical properties on the behavior of the reservoir. From this, a new approach for the decline curve analysis of fractured formations is developed that relates the production decline trend not only to the Warren and Root's key parameters (ω, λ), but also to the elasticity parameter (ε) which reflects the mechanical behavior of both the rock skeleton and the fractures.

The concept of stress-dependent skin around the wells producing from NFRs is discussed and formulated in this work. The behavior of such NFRs at different flow periods are described, from which we found that the effective-stress change can affect the decline-curves from stress-sensitive fractured formations.
Lightweight Cementing Design Improves Zonal Isolation on Challenging High Temperature Offshore Thailand Wells
Authors: Brandl A. , Acorda E. R. , Doherty D. R. , Rajaneekornkrilas V.
Published: October 2011

A cementing system was developed with advanced performances for wellbore zonal isolation in the Gulf of Thailand. Wells in the area are located in shallow water and characterized as deep and hot, with low fracture gradients, with deviated wellbore trajectories. Fast-paced drilling activities and working within the offshore logistical parameters further challenge cementing operations and slurry designs. The paper will discuss laboratory test results and a case history focusing on the significant benefits of a lightweight cement system developed to achieve zonal isolation of wellbores under the given extreme conditions. A sidetrack of a well in the Gulf of Thailand was cemented with the novel cementing system. Cement bond log evaluations confirmed significantly better results in comparison to the cement system used to cement the initial section. These findings were also attributed to the improved slurry performances of the novel cementing system.
An Improved Model for Wireline Formation Tester Pumpout Time Estimation
Authors: Ali Khan Waqar , Wattenbarger Robert A. , Shah Syed Shabbir , Akram Agha Hassan
Published: October 2011

Wireline formation testers are now in their third generation of development. These tools are used to measure formation pressure andpermeability, and to take fluid samples from the reservoir. Technological developments over the years have resulted in a modular tool that can obtain a clean formation fluid sample with minimal contamination. Sampling time varies from a few minutes to many hours depending upon different parameters i.e. depth of invasion, flow rate, formation permeability, anisotropy, porosity and the viscosity of the involved fluids including mud filtrate and formation fluids.

Total pumpout time required to obtain a clean sample is always of interest to both the operator and service company owing to economics, well stability and other factors. An approach is required that is flexible and that requires few parameters to estimate the pumpout time and the time for first formation fluid slug.

In this study a new polynomial model is developed to better estimate the time to first slug.

The new model was tested for different pumpouts from different wells and history matching was performed to test the accuracy of the model. A number of pumpouts were considered and all of those showed close matches. Software was developed to quickly calculate the total pumpout time at real time. Also in this study the previous model was tested and with the limited available data the new model showed much improved results over the previous model.
Downhole Isolation Packers for Drilling Operations: Field Experiences
Authors: Ferrara P. , Molaschi C. , Oppelt J. , Buda R. , Amicosante M. , Grimmer H.
Published: October 2011

In recent years, with the availability of high-performance automated drilling systems, the drilling challenge has moved to even further critical operations involving deepwater and ultra-deepwater environments, HPHT applications, anomalous pressure regimes and reduced margins between pore and fracture gradients. Even though prevention comes first, achieved through best practices and master operating attitude, the availability of tools and procedures to cope with critical events is very important. Nowadays, whenever necessary, a best oil industry practice is represented by Managed Pressure Drilling Systems. These systems consist in a set of surface tools and equipment that enhance drilling capacity and grant a safe drilling process. In case of emergency, the reaction is usually fully devoted to these systems and the blowout preventer (BOP).

For many years, the possibility of introducing both static and dynamic safety barriers directly into the well has been considered to limit the intensity of kick events and achieve a consistent increase of safety. This paper describes two field experiences (in the US and Italy) achieved with downhole isolation packer subs that can be integrated in the drillstring to operate in an open hole as well as above the last casing shoe. Risk-assessment advantages obtained with this technology are also analyzed and reported.

As dynamic barriers, downhole isolation packers complement conventional BOP systems and work in combination with them, to: stop a kick close to the bit, improve well integrity and optimize well control procedures. In case of a kick, while closing the surface BOP is according to standard practices, a downhole isolation packer, as part of the drillstring, can be activated by means of a downlink. The well annulus will be shut in, trapping the kick below the tool, thus enabling it to condition the mud above it and to bullhead the kick back into the formation.
A New Way to Waste Recording, Waste Tracking, and Waste Reporting to Improve Waste Management
Authors: Rusjanto J. , Hartoyo O. , Qory F. , Aripin A. , Saroso R. , Rohman K.
Published: October 2011

Waste management shall be done comprehensively, starts from waste generator to final disposal. Waste management should base on Reduce, Reuse, Recycle, Recovery, and Disposal (4R+1D) principles. A good waste data management will enable us to promote waste management improvement based on these principles. Waste management data consist of waste recording, waste tracking, and waste reporting.

In Total E&P Indonesie, every waste that generate by every entity in each production sites and drilling rigs will be recorded in waste register/Log book. Waste from every site will be transferred to final disposal (senipah) via transit area (handil). Every waste that transfers will be recorded and attached with Waste Transfer Note (WTN) form. Both of this recording system is a paper based systems and has several disadvantages. First, when compiling the waste data from waste register and waste transfer note, there is discrepancy of waste quantity between both of record systems. Second, it needs a lot of man hour to compile the waste data from both recording systems and human error is most likely happen here because of manually recapitulation of waste data which will directly affect the waste data that submitted to authority. Third, it is very hard to track the waste position when transferred, whether it has already arrived in transit area or final disposal because the control paper (Green parts of waste transfer note (WTN) form) often does not come back to waste generator.

Total E&P Indonesie developed an application which aim to replace the waste register and waste transfer note and also solving the entire problem that caused by previous systems. This application is an integrated system of waste register, waste tracking, and waste reporting.

This application called WISEMan. It has a lot of benefit. First benefit is waste recording, tracking, and reporting will need a short time which can minimize man hours. Second benefit is waste engineer in Total E&P Indonesie can focus on Improving Waste Management that refer to Reduce, Reuse, Recycle, Recovery, and Disposal (4R+1D) Principles, and third benefit is improving awareness of waste segregation to all personnel in TEPI premises because the WISEMan system makes the employee compulsory to segregate the waste that generate by each entity.
Impact of Upscaling on 3-D Modelling of SAGD in a Meander Belt
Authors: Deschamps R. , Guy N. , Preux C. , Lerat O.
Published: October 2011

This work aims at assessing the impact of heterogeneities on heavy oil recovery through SAGD process by using numerical models of a reservoir analogue of meander belt. These models are obtained with different scales of upscaling of the geological model.

Meander belts consist of point bar deposits, characterized by a 3D complex internal architecture, with different scales of heterogeneities, which distribution is associated with the depositional processes.

Based on a 3D outcrop description of a meander belt analogue to the Canadian heavy-oil fields, the approach includes four steps: 1/ the construction of a reference static reservoir model based on a very fine description of the outcrops in terms of architecture and geological heterogeneities, 2/ upscaling of the grid at different scales using different methods in order to evaluate their impact on the heterogeneity distribution in the reservoir, 3/ reservoir SAGD simulations using horizontal well doublet (steam injector and producer) across the meander belt, to assess the impact of upscaling of heterogeneities effect and on heavy oil production.

The impact of heterogeneities on simulation results are evaluated for several upscaling stages. Results show that heterogeneity distribution has an impact on fluid flow at different stages of production. On the fine gridded model, small scale heterogeneities impact the steam chamber development and fluid flow in the wellbore vicinity at the beginning of the steam injection, whereas large scale heterogeneities strongly influence oil recovery during the whole recovery process and lower the efficiency of the reservoir drainage. On coarser grids, the effect of small scale heterogeneities can be smoothed, depending on the upscaling stage. The geomechanical effect is not taken into account in this work, the goal being to assess the impact of heterogeneities on oil recovery.

The performance of SAGD is clearly linked to the steam chamber development, which depends on the degree of heterogeneities present in the reservoir. The simulation workflow and the sensitivity study based on different upscaling methods contribute to better restore the heterogeneity distribution in the reservoir. The negative impact of these heterogeneities during the oil recovery must thus be quantified in order to monitor the thermal production at crucial periods of production.
The Use of Slotted Expandable Liners in Multizone Openhole Frac-Packs: A New Completion Concept
Authors: Mason David , Duhrkopf Don , Morgan Quentin , McGeoch Andrew , Jones Colin
Published: October 2011

Sand production is becoming increasingly problematic due to the exploitation of poorer quality reservoirs and depletion of existing reservoirs. Cased hole frac-packs (CHFP) combine reliable sand control with potential for high productivity, and have become the completion of choice in many provinces. However, CHFP completions manifest in limited flow entry area into the well. This may cause two problems; a loss of productivity and potential screen erosion.

In CHFP designs it is common to perforate the casing with high shot density big hole charges, but due to shot orientation and phasing, only a relatively few perforations connect with the fracture. Entire well production therefore originates from 4spf or less. Detailed modeling shows that this will not cause productivity impairment if the proppant pack is undamaged. Predicted skins for undamaged CHFP should be slightly negative, but field observations in one particular region show typical skins of 2 to 5, but with skins above 10 also reported. This tends to suggest that proppant permeability is being reduced in-situ.

By contrast, productivity of open hole frac-packs (OHFP) is significantly less impacted by proppant damage and they also greatly reduce screen erosion risk. The productivity enhancement is revealed through detailed inflow modeling and laboratory experiments.

However, it is difficult to engineer multi-zone OHFP completions, and wellbore stability issues complicate implementation. These limitations can be resolved by setting field-proven expandable completion liner (ECL) in the openhole section, prior to running the inner sand screen completion and frac-pack tools. Experiments on large scale samples show that ECL stabilizes the borehole. ECL slot geometry also results in 3-5 fold increase in fracture connection area compared to CHFP.

ECL technology can also be combined with a number of different zonal isolation packer technologies, such as expandable, mechanical, swell and combo packer designs, to segment zones. This gives ECL frac-packs (EFP) the functionality of a multi-zone CHFP, but mitigates productivity impairment through proppant plugging and also screen erosion risk. The EFP completion concept also removes a casing string and eliminates perforating, and so also reduces HSE risks. It also has the potential to accommodate larger screen sizes, slim well designs and to reach deeper targets. The EFP completion concept also relies on integration of existing technologies, while offering the potential for a step change in well performance.
Minimum Transport Velocity Models for Suspended Particles in Multiphase Flow Revisited
Authors: Bello K. O. , Oyeneyin M. B. , Oluyemi G. F.
Published: October 2011

Increasing trend in the transportation of unprocessed reservoir fluid from assets located in remote locations and the drive towards maximising existing facilities and optimising production has encouraged many deepwater operators in the use of long subsea tiebacks.

However, the main challenges associated with unprocessed multiphase fluid flow in long subsea pipelines relate to constantly changing patterns and the likelihood of the suspended particles to settle out of flow and deposit in the transfer pipeline causing partial or complete blockage. Flow pattern transition is therefore a critical factor that must be accounted for in any particle transport models. However, current particle transport models do not account for these critical factors; besides the experimental data on which these models were validated are limited. Therefore they are often unreliable when subjected to varying operating conditions.

In this paper preliminary minimum transport velocity (MTV) models developed for rolling and suspended particles under different flow patterns are presented. The concept of particle velocity profile provided the basis on which the models were developed. Further work is planned to acquire large experimental data for the purpose of validating these proposed models.

The problem has been largely attributed to insufficient flow velocity among other parameters required to keep the solids in suspension and prevent them from depositing in the pipe. Additional complexities are introduced because of different flow regimes that occur within the pipe flow depending on the gas and liquid flow rates.

The development of minimum transport velocity models for suspension and rolling based on the concept of particle velocity profiles is a significant breakthrough in particle transport in multiphase flow. This has the potential to solve problems of pipe & equipment sizing, risk of sand deposition & bed formation, elimination of costs of sand unloading, downtime and generally improve sand management strategies.
Brilliant Water Shut-off Application Bypassing Existing Fish: A Success Story at Angsi Field, Malaysia
Authors: Johan M. Alham , Jalil M. Izwan , Ghazalli Rohaizat , Razak M. Hairi
Published: October 2011

Angsi is one of the major fields for PETRONAS Carigali Sendirian Berhad. Located at offshore Terengganu in the Malay basin area, Angsi had become the top priority in terms of oil production. One of its oil producers, A-66L was idle since 2007 due to high water cut observed after few years of production. Due to its high inclination, their first attempt to perform water shut-off and additional perforation were decided to be conveyed by electric line tractor.

The job, planned to isolate the I-33 zone using a mechanical bridge plug conveyed by eline tractor, turned into a major failure when the plug is suspected to get stuck in hole. The incident happened during pulling out the tool after activating it and the decision made at that point of time was to cut the eline cable at surface and to temporarily suspend.

Fishing job using braided line was successfully done after that. A total of 4800 meters eline cable was successfully retrieved and left the well with the failed mechanical bridge plug which was set above the targeted zone to be isolated. The team had come out with a brilliant idea of shutting off the water out zone and successfully perforated the new zone of interest with a small clearance from the existing top of fish. The well is now producing about 400 bopd.

This paper will discuss in detail the complexity of the overall operation, well challenges, water shut off bypassing existing fish and the selection criteria of perforation techniques to accommodate the small clearance. The decision making process and well intervention equipment selection will also be highlighted throughout the overall job operations.
A Dynamic Model for Simulation of Integrated Reservoir, Well and Pipeline System
Authors: Sagen Jan , Østenstad Monica , Hu Bin , Henanger Kjell Eirik , Lien Siv Kari , Xu Zhenggang , Groland Steinar , Sira Terje
Published: October 2011

Most reservoir simulations use vertical flow performance (VFP) tables to represent flow in the tubing, which ignores the flow dynamics in wells and their downstream gathering and transportation networks. On the other hand, most dynamic well-pipeline flow models use pressure-rate equations to describe the inflow/injection from/to the reservoir, which ignores the flow and pressure transients in the near-wellbore regions. Obviously, neither of the two types of modeling can account for the transient reservoir-well/pipeline flow interactions that can be of great importance in many operation scenarios.

To bridge this modeling gap, a joint industry program (JIP) was initiated based on a previous successful investigation [1] on the feasibility to implicitly couple a reservoir model to a dynamic well-pipeline multiphase flow model. The aim of the JIP was to deliver a simulation tool that can fulfill the industry's basic requirements on the modeling of transient flow interactions across the sandface, which should also lay the foundation for its future expansion in functionalities. This paper is intended to summarize the outcomes of the JIP.

First of all, the paper discusses the need for integrated dynamic modeling and reviews earlier efforts on building integrated dynamic reservoir-well/pipeline systems. Secondly the paper describes the details of building the reservoir model and how to couple it to a well-pipeline flow model to assure numerical stability and simulation speed for cases of interest. Thirdly, the paper shows the PVT and fluid handling options the integrated simulation tool can provide. These are identical for the two models in order to keep the consistence of fluid properties particularly when the same fluid flows back-and-forth between the wellbore and the near-wellbore during transients.

Two application cases based on the resulting model are presented in the paper. One case is about simulation of chemical squeezement hydraulics for refining the operational procedure, and the other case is about quantification of the pressure gradient in the near-wellbore formation for different well bean-up procedures in order to prevent sand production. The two cases demonstrate the advantages of using the coupled wellbore-reservoir transient modeling.
Impact of Supercritical CO2 Injection on Petrophysical and Rock Mechanics Properties of Chalk: An Experimental Study on Chalk from South Arne Field, North Sea
Authors: Alam Mohammad Monzurul , Hjuler Morten Leth , Christensen Helle Foged , Fabricius Ida Lykke
Published: October 2011

Changes in chalk due to EOR by injecting supercritical CO2 (CO2-EOR) can ideally be predicted by applying geophysical methods designed from laboratory-determined petrophysical and rock mechanics properties. A series of petrophysical and rock mechanics tests were performed on Ekofisk Formation and Tor Formation chalk of the South Arne field to reveal the changes in petrophysical and rock mechanics properties of chalk due to the injection of CO2 at supercritical state. An increase in porosity and decrease in specific surface was observed due to injection of supercritical CO2. This indicates that a reaction between CO2 enriched water and particles takes place which smoothens the particle surface. Accordingly, partial increase in permeability was also noticed. An effect is also observed from the decrease in pore-space stiffness, calculated from sonic velocity. No significant effect on wettability as indicated by NMR T2 relaxation time was observed. Rock mechanics testing indicates that in 30% porosity chalk from the South Arne field, injection of supercritical CO2 has no significant effect on shear strength and compaction properties, while there is probably a slight decrease in stiffness properties. For both the Tor Formation and Ekofisk Formation, flooding with CO2 after waterflooding does not seem to affect the shear strength parameters. For the Tor Formation, the elastic deformation parameters seem to be reduced after CO2 injection. In contrast, the effect on the elastic moduli in Ekofisk Formation is insignificant. The time dependent properties for both Tor Formation and Ekofisk Formation do not seem to be affected by CO2 flooding in the relevant stress regime. Generally, the change in both petrophysical and rock-mechanics properties is insignificant in Ekofisk Formation, compared to the changes in Tor Formation, most probably due to the very little contact cement in Ekofisk Formation chalk. Time-lapse monitoring strategies may be required during a CO2-EOR process for the measurement of changes in reservoir properties that may cause deformation of and leakage from a reservoir. Results of this study will provide data for designing future monitoring strategies based on 4D seismic.