bluuebunny/crossref_metadata_2025 huggingface dataset:
Downhole Disposal of Black Water – Engineering Re-design
Authors: Deng Lianjun , Wang Parker , Chen Kaijun
Published: July 2010

Traditional treatment of black water on offshore facility is grind, disinfect and discharge overboard. But in some environmentally sensitive seas, offshore discharge of black water from the facilities was limited by the regulatory agencies. Therefore the black water effluent from the living quarters on the facilities can be disposed of in a safe, environmentally prudent and economic manner. To achieve this goal, process must be re-designed in terms of treatment capacity, effluent quality, particle size and re-injection process. There are always some other wastes been re-injected such as cuttings, waste mud, packer fluid etc. Principles are given in this paper on process re-design to guide a successful and effective system upgrading.
Increasing the Service Lifetime of Coated Titanium Anodes
Authors: Hoseinieh S. M. , Ashrafizadeh F. , Maddahi M. H.
Published: July 2010

Mixed metal oxide coated titanium anodes have been applied widely to cathodic protection as impressed current anodes in the oil/gas industry and for chlorine production in chlor-alkali industry. The anodic stability and service life are the main concerns in these applications. It has been known that oxide anodes have a very limited service life under operating conditions because of the severe corrosion of active component in the oxide mixture such as RuO2, leading to final deactivation of the anode.

To increase the effective life of anodes, this study considered alternative anode materials and concluded that the anode life is improved by doping the anode coating with IrO2. Therefore, corrosion behaviour of a RuO2-IrO2-TiO2/Ti oxide anode was investigated during an accelerated life test (ALT) in NaCl solution by use of cyclic voltammetry (CV), electrochemical impedance spectroscopy (EIS) and SEM/EDS. The service lifetime of IrO2 doped oxide coating is compared with RuO2/Ti and RuO2-TiO2/Ti anodes and a systematic evaluation is presented.

The life test indicated that the improved oxide anode has a long lifetime and appropriate activity. It was concluded that RuO2-IrO2- TiO2/Ti anodes last up to ten times longer than Ir-free anodes. An impedance model is then developed for this corrosion system and the model simulation compared to the experimental data. The model is shown to be in reasonable agreement with the experimental data. A comprehensive deactivation mechanism of titanium anodes has been proposed by the growth of an insulating TiO2 layer at coating-substrate interface.

The results presented in this paper are very promising and reveal that RuO2-IrO2-TiO2/Ti anode has a good potential to be used as mixed metal oxide anode in oil/gas and petrochemical industries.
A New Approach to Deformable Fractured Reservoir Characterization: Case Study of the Ekofisk Field
Authors: Shchipanov A. A. , Kollbotn L. , Surguchev L. M. , Thomas K. O.
Published: July 2010

Production from a fractured reservoir is generally governed by the fracture network conductivity, which may be altered by changes in reservoir pressure. A new approach to naturally fractured reservoir description accounts for the variation in the fracture properties caused by the effective stress change. The basis of the proposed approach is a compressible discrete fracture network (CDFN) model with stress dependent fracture aperture and hence porosity and permeability. The new approach allowed us to develop a workflow to evaluate the stress dependent fracture properties. This workflow includes inverse and direct problem solutions. The inverse problem consists of interpretation of pressure transient well tests and production history integrating geomechanical effects. The results of core analyses, production logging and wellbore imaging provide important information for the CDFN characterization. The direct problem consists of numerical flow simulation focused on calibration of the obtained fracture properties to match well test data. Using the workflow, one can determine stress or pressure dependent fracture parameters to be used in single and dual porosity reservoir simulations.

Using available field data, the proposed approach allowed us to improve characterization of the Ekofisk fracture network. The seafloor subsidence and chalk compaction observed at Ekofisk have initiated extensive studies of the reservoir geomechanics. The geomechanical effects were integrated in the reservoir characterization using the developed workflow. A decrease in well productivity and fracture conductivity due to pressure decline was obtained from the pressure transient and production analyses. This allowed us to describe the dynamic behavior of the fracture permeability and porosity. These fracture properties were then used in reservoir simulation. The simulation results have given evidence that dynamic reservoir behavior has an effect on multiphase flow comparable to well placement and relative permeability effects.
A New Computer Assisted History Matching Method
Authors: Abrahema Fathe A. , Heinemann Zoltán E. , Mittermeir Georg M.
Published: July 2010

This work presents an automatic history matching approach called Target Pressure and Phase Method or TPPM. In a conventional history matching approach the model wells are fixed and one seeks for a reservoir model, in which the historical rates, well pressures, WC and GOR are provided over the entire time. The presented method does the opposite. The reservoir model is given and the computer automatically places wells, which can do what they should do – namely correctly reproduce the measured data. These pseudo wells are perhaps at different locations and connect to other layers as the real wells but the overall material transfer will be correct for the entire time period. If such wells cannot be placed, then the static model is fundamentally wrong and must be replaced. Stochastic realisations can be screened at this level already. Supplementary, water is added into the model boundaries, ensuring that the average pressure in any chosen region closely follows the historical pressure. After the global match has succeeded, the pseudo wells are shifted towards the real ones and the reservoir and perforation properties will be tuned step by step, partly automatically partly manually. The history match is completed after all pseudo wells have been replaced by the model wells.

The method is implemented in PRS, a fully developed not commercial user friendly tool. It can be used standalone but also as a pre-processor to ECLIPSEc. The tool needs some command lines added to the ECLIPSE input only. PRS writes out a modified SCHEDULE file containing the actual settings of the pseudo wells and the parameters for the Fetkovich and Carter-Tracy analytical aquifer models (replacing the boundary injections) for the next ECLIPSE run. The paper describes the concept, the corresponding algorithms. The applicability is demonstrated on a small scale example and additionally with a successful field case.
Development and Qualification of a New Wireless Controlled Retrofit Safety Valve: An Alternative to Well Workover that Enhances Well Safety and Maximizes Production Uptime
Authors: Champion B. P. , Gandini G. , Gabbiani A.
Published: July 2010

There are many examples of wells around the world today that are shut-in due to failure of the Surface Controlled Sub-surface Safety Valve (SCSSV). Whilst these valves are generally very reliable, the control line that runs to surface in the annulus is susceptible to plugging by contaminants in the hydraulic control fluid and also to corrosion, which causes leaks; both are outcomes that render the valve inoperable. The failure of the control line also means that the contingency solution of installing a Wireline Retrievable Surface Controlled Sub-surface Safety Valve (WR-SCSSV) is not possible.

When a safety valve fails, the most common remedial solution today involves installing a Sub-surface Controlled Safety Valve (SSCSV), such as an ambient valve or storm choke. Whilst this solution is lower cost and more straightforward than performing a full rig-based well work over, it is not as safe. SSCSVs are directly influenced by changing well flow conditions, such as high flow rates, low pressures, or by water slugs, and thus are notoriously unpredictable in operation. Additionally, they are not controllable from surface and not fail-safe, which is undesirable from a well control and safety standpoint.

By transmitting electromagnetic (EM) signals from surface to downhole, it is possible to control downhole hardware. A wireless controlled safety valve has been developed that can be retro-fitted into a well using conventional slickline intervention equipment and procedures. Being controllable from surface and of a fail-safe closed design, this valve offers both functional and safety advantages over existing SSCSV solutions. This new valve also offers a retro-fittable solution for wells having no hydraulic control line installed. In situations where a capillary string may need to be installed for foam or chemical injection purposes, it also provides an opportunity to free up the hydraulic control line.

A prototype valve was subjected to qualification and functionality testing in accordance with a modified ISO 10432 test procedure. This testing was followed by installation in an onshore gas well for a 6 month trial that involved both flowing and injection phases. The valve was cycled and inflow-tested regularly and performed reliably, consistently and fully in accordance with specification throughout the trial period.

This successful trial of a new wireless controlled safety valve marks the introduction of a more controllable and predictable alternative to an ambient valve or storm choke, minimises deferred production and increases the well's safety. Following the successful onshore trial, the valve is now considered ready for wide scale field application onshore and at the time of writing this paper, plans for performing a first trial on an offshore platform are well advanced.
A New Approach to Thin Oil Zone Modeling in High-Dipping Multilayered Reservoirs
Authors: Tolstukhin Evgeny , Olivier Pierre
Published: July 2010

This paper focuses on maximizing oil recovery from thin oil rim in a high-dipping, multilayered reservoir in the North Sea.

Oil output from thin oil zones between a gas cap and an aquifer is limited to uneconomical rates caused by water coning and gas cresting. Horizontal wells are widely used in thin oil rim development due to the limited pressure drawdown applied to the formation. The horizontal wells should be optimally positioned within the oil zone to avoid premature gas and water breakthrough.

Critical issues for thin oil zone reservoir modeling are correct grid representation of internal heterogeneities, fluid saturation distribution, fluid contacts, horizontal well trajectories and flow displacement properties.

In a stratigraphic grid, the lack of resolution affects the fluid contacts movement within the high-dipping reservoir layers. Similarly for a horizontal grid, thin reservoir intervals are truncated due to a ‘stair-casing’ effect, which leads to loss of communication within the layers.

A hybrid grid was constructed to combine the benefits of the horizontal grid in the oil zone together with the stratigraphic grid in the water and gas zones. Such a grid framework provides the best modeling approach for representing the transition zone and fluid contact movements.

In the study, the prediction of oil, gas and water production in the transition zone was difficult because the crude oil altered formation wettability after hydrocarbon migration and reservoir structure tilting. Multiphase flow was modeled by integrating the key dynamic reservoir controls, translated into end-point correlations above the free water level based on multivariate SCAL data analyses.

Comparative analyses of alternative modeling techniques exhibited clear differences in the response for coning development and optimal well placements.
Modeling and Optimization of Asphaltene Deposition in Porous Media Using Genetic Algorithm Technique
Authors: Hematfar V. , Kharrat R. , Ghazanfari M. H. , Bagheri M. B.
Published: July 2010

Different models have been proposed for deposition of asphaltene on reservoir rocks that due to complexity of asphaltene nature, most of them have not been productive. Here, a reliable model is proposed which despite of previous models, considers the change in asphaltene saturation in the core. The obtained experimental data in the laboratory was used for model validation. In this work, a series of core flooding tests was carried out in presence of connate water at different solvent-oil volume ratios. Pressure drop was measured at three different terminals along the core. The obtained experimental data as well as mass balance equations, momentum equation, asphaltene deposition and permeability reduction models were employed in an iterative scheme to simulate the deposition process. Genetic algorithm (GA), which is a powerful tool, was applied for history matching, optimization and determination of the model parameters. Well match observed between the model results and experimental data confirms the accuracy of the proposed mathematical model of asphaltene deposition in porous media. Also, applied improvement on the model resulted in accurate simulation as well as determination of precipitated asphaltene saturation. Optimization shows that all deposition mechanisms, surface deposition, entrainment and pore plugging, are dominant during the permeability evolution process. Results of this work can be helpful for reliable simulation of the dynamic asphaltene deposition process during different production schemes.
Deployment, Monitoring and Optimisation of a Scale Inhibitor and Associated Corrosion Inhibitor within a Deepwater Subsea Facility, Offshore Brazil
Authors: Jordan M. , Linares-Samaniego S. , Santos Afonso M.
Published: July 2010

This paper presents field results and lessons learned from an FPSO, Offshore Brazil where a scale and corrosion inhibitor has been applied subsea to control both the deposition of scale and associated corrosion.

The paper outlines the problems encountered when the initial scale inhibitor formulation was deployed in the field related to materials compatibility with the subsea manifold and the steps taken to develop and monitor an improved formulation. Problems that can affect product application in a subsea environment, including deposition of suspended solids within the chemical, hydrate formation, incompatibility of the chemicals with umbilical material and produced fluid, will all be addressed. The laboratory methods used to select the product along with measurement methods used in the field are also discussed. The validation of the laboratory selection methods in the field required the development of a monitoring program to establish base line control and to assess the degree of protection from scale deposition and corrosion across the process.

The use of novel real time scale monitoring, as well as water chemistry tracking proved vital to the understanding of the efficiency of flow assurance within the processes and how treatment rates of the scale inhibitor and corrosion inhibitor could be optimised.

This paper will outline in detail the particular issues associated with chemical injection to a subsea facility, many of which are currently being developed in the Gulf of Mexico, offshore West Africa and Brazil. This case study is a good example of lessons learned and sharing of best practice from another oil basin.
FAST Optimization of Line-drive Water Injection
Authors: Lafond Kim Bousquet , Pedersen Lars M. , Christiansen Lars Bo
Published: July 2010

The Halfdan Field has been developed with long parallel horizontal wells using alternating producer/injector pairs (Figure 1). Using the Fracture Aligned Sweep Technology (FAST) the injectors were hydraulically fractured along the wellbore to increase injectivity and enhance the sweep geometry. The anticipated FAST fracture orientation has been verified by 4D seismic interpretation and confirms the geomechanical concept of FAST.

As reservoir pressure increases the fractures tend to close. This provides an opportunity to further increase injection pressure. However, the risk of extending the fracture into the Halfdan spine wells makes it necessary to increase injection pressures in a controlled manner.

This paper provides a method to operate water injection at the field's performance limit. The following tools have been applied, further developed and confirmed by field data.

Fall off testing to Estimate Current Fracture Heights: Analysis of more than 200 falloff tests to estimate fracture height and to identify opportunities for increased injection rates. Step Rate Tests to Increase Injection at Unchanged Fracture Height: Execution and analysis of more than 60 Step Rate Tests to increase injection rates at constant fracture height. Controlled Fracture Criterion to Control Fracture Propagation: Development of correlations for fracture height vs. injection pressure and fracture opening pressure vs. voidage to identify performance limits and improve the control of the fracture propagation.

An average pressure gain of 80 psi per injector corresponding to a total of 8,000 bbl/d of injected water has been achieved for the 26 Halfdan water injectors. The incremental oil gain from this is estimated at 3,500 bbl/d. Better fracture height control and propagation, securing reserves by lowering the risks of producer-injector short circuits, has been achieved through an improved understanding of fracture behavior from fall off tests and correlation between pressure, rates and voidage. This method has successfully been applied at field scale with proven results and is refined with the acquisition of new field data.
Development of a Data Partition Technique for Gradient-Based Optimization Methods in History Matching
Authors: Ding D. Y.
Published: July 2010

Assisted history matching is now widely used to constrain reservoir models. However, history matching is a complex inverse problem, and it is always a big challenge to history match large fields with a large number of parameters.

In this paper, we present a new technique for the gradient-based optimization methods to improve history matching for large fields. This new technique is based on data partition for the gradient calculations. The objective function is first split into local components, and the dependence of each local component on principal parameters is then analyzed to minimize the number of influential parameters. The interaction between parameters and local components is allowed in the splitting. Based on this study, we can propose a perturbation design, which allows us to calculate all derivatives of the objective function with only a few perturbations. This method is particularly interesting for regional and well level history matching, and it is also suitable to match geostatistical models by introducing numerous local parameters. This new technique makes history matching with a large number of parameters (large field) tractable.
Effect of Shaped Charge Case Materials on Perforating Guns
Authors: Han C. , Du Michael H. , Ference Bob
Published: July 2010

Detonation of shaped charges carried by a perforating gun creates a complex physical and chemical process that occurs within a very short time. During the process the shaped charge case usually disintegrates and is partially oxidized. The oxidization emits heat in addition to that of the explosive detonation and hence could eventually affect the post-detonation condition of the perforating gun.

Zinc and steel are common materials used in the manufacture of shaped charge cases, but their physical and chemical properties result in quite different impacts on the performance of the perforating gun and on its survivability. About 1,000 ms after detonation, a charge with a zinc case generates a pressure approximately 50% higher than one with a steel case. The zinc case creates an impulse about 30% higher and a temperature about 220°F higher. It results in more than 45% oxidation; for the steel case oxidation is less than 5%. Conversely, the zinc and steel case contributions to the detonation process are quantifiable in terms of energy. Such a quantified study is first reported in respect to perforating. Details can be incorporated into a recently developed gun survivability model for risk management in both new perforating product development and job execution. In field operations it can be used in post-perforating evaluation of formation damage.
Numerical Modelling of a Well Test Affected by Condensate Banking and Comparison with Analytical Interpretation
Authors: Botteon A. , Monico C.
Published: July 2010

Condensate banking consists of a liquid accumulation in the formation around a gas well when pressure drops below dew point. This can strongly compromise well deliverability. A numerical simulation study was carried out to reproduce data measured during a DST test in an exploration gas well where condensate banking had been assumed based on analytical interpretation.

A compositional radial model was built to study the evolution of fluids in the formation around the well. Numerical simulation captured the generation of condensate banking at the producing conditions of the DST. An analysis of simulated build-up pressures showed qualitative agreement with actual data in the double stabilization of the derivatives. Sensitivities were performed on the critical oil saturation above which condensate is mobile and on the permeability anisotropy ratio.

The effects of velocity dependent relative permeability and non Darcy flow were also investigated.

A match was obtained between the numerical simulation output and the analytical interpretation results in terms of radial extension of condensate banking and pressure build-up derivative.

Numerical simulation validated the classic analytical interpretation of well test and also provided a more accurate comprehension of condensate distribution in the vicinity of the well. This demonstrated the capability of a simulation model to reproduce the condensate banking process and the effects on build-up pressure. Moreover, the sensitivity results limited the uncertainty on investigated parameters.

Well test modeling provides a powerful method to confirm the possible formation of condensate banking based on analytical interpretation results.
Applying Multi-Node Intelligent Well Technology for "Active" Control of Inflow Profile in Horizontal/Inclined Wells
Authors: Sun Kai , Guo Boyun , Saputelli Luigi
Published: July 2010

Non-equalized production influx along the horizontal or inclined wellbore is believed to be responsible for early water/gas breakthrough in oil production wells. Non-equalized water injection distribution has been recognized to cause poor sweep efficiency in waterflooding. The non-equalized fluid flow is attributed to reservoir heterogeneity and frictional pressure drop along the wellbore. A practical means of minimizing the problem is to use inflow control devices (ICD) between isolation packers to adjust the production influx or injection distribution within the isolated compartments. However, the ICDs are passive devices, i.e., once they are set in place in a completion string they cannot be adjusted to ensure equalized flow when reservoir conditions change during oil production or water injection. This paper introduces a new technology called Multi-Node Intelligent Well System (MNIWS) that is under development and will be soon available to the industry.

Starting with analyzing the data from an existing horizontal well with an ICD installation, we derived a new completion design for oil production wells using the MNIWS. Computer modeling of well performance shows that the MNIWS technology suite can equalize production influx and delay water breakthrough into the horizontal wellbore more effectively than conventional ICDs; in particular when inflow conditions change during the well's life.
Inhibition of Sodium Soap Emulsions, West Seno, Indonesia Field
Authors: Gallup Darrell L. , Denny Vitus , Khandekar C. Y.
Published: July 2010

In the Kutei, Indonesia oil and gas producing basin, a serious flow assurance problem has occurred in the form of an oil-water emulsion. This emulsion, formed via the reaction of carboxylic acids in oil with sodium-chloride-bicarbonate-acetate produced water, is difficult to break. At the West Seno deepwater field, the floating production unit (FPU), utilizes heat and an acidic demulsifier to break the emulsion into salable oil and water suitable for overboard discharge. Over the past couple of years, a few wells have begun to produce an emulsion that is not easily broken by the FPU heat/acid demulsifier process. Characterization studies of the new emulsion show that it is very different chemically from the common sodium soap emulsions produced at West Seno field since production inception in 2003. The former contains primarily sodium alkyl benzoates, while the latter consists primarily of sodium n-alkanoates ranging from C10 – C36. Oil produced from the wells that produce the new "difficult" emulsion is waxier than normal. The combination of waxes and the alkyl benzoic acids is apparently responsible for the formation of the "difficult-to-treat" emulsion.

Laboratory screening tests of new sodium soap emulsion inhibitors have shown that heat and several non-acid inhibitors break the emulsions more efficiently than the incumbent acid demulsifier. One new inhibitor was especially efficient and more cost effective than all other inhibitors included in the study. Not only is this new inhibitor more effective at a lower dosage, but its bulk price is also less. This inhibitor was injected into two West Seno wells that produce the "difficult" emulsion in a short field trial. Coupled with reservoir heat, the inhibitor successfully broke the emulsion at a reasonable dosage. The chemical appears to inhibit sodium alkyl benzoates and sodium n-alkanoates via a complexation mechanism. We are now preparing for commercial deployment of the new inhibitor in West Seno wells. We believe that the new inhibitor will eliminate or reduce the need to treat fluids on the FPU with the incumbent acidic demulsifier, which should reduce corrosion and by-product scaling caused by the incumbent.
Selection of Filler Materials to Minimize Preferential Weld Corrosion in Pipeline Steels
Authors: Mahajanam Sudhakar P. , Joosten Mike W.
Published: July 2010

Preferential weld corrosion (PWC) has long been a problem in the oil and gas industry for pipelines used in process facilities, seawater injection, produced water service, offshore platforms, and downhole production systems. This paper reviews recent PWC field failures in light of mitigation guidelines from existing literature. Environmental effects take precedence over chemical composition and microstructure in determining PWC susceptibility. Therefore, the primary approach to minimize PWC is continuous corrosion inhibition. The ideal PWC prevention method would be the use of autogenous welds or welds made with matching consumables. However, this is not a practical option in the field where most pipelines are typically made from carbon-manganese steels with broad chemical compositions, thereby making them susceptible to PWC. The feasible alternative is to use filler materials with strict compositional control vis-à-vis the following elements: nickel, silicon and chromium. In addition, increased preheat and high heat input welding processes should be employed to minimize PWC susceptibility.
Development of Downhole Explosion Monitoring System for Gas Drilling
Authors: Kai Lan , Shugang Hou , Jiaqi Gong , Youming Xiong , Chengkai Li
Published: July 2010

Continental strata in Northeast Sichuan presents poor drillability due to high formation pressure, which leads to low ROP, wellbore inclination and lost-circulation with mud drilling technique. Gas drilling not only dramatically improves ROP and well quality, but also decreases construction cycle. However, this method was apt to trigger downhole explosion through payzones drilling, which would result in downhole tool broken, drilling failure and even well abandonment. During the exploitation of gas reservoirs in Northeast Sichuan, downhole explosion has happened in P104-1, P303-1, Y2 and Y3 wells, and these severe accidents provide an important incentive for developing a downhole explosion monitoring system for gas drilling to decrease downhole explosion risk. This paper will focus on the development of this system based on MIC-2718-a high-gain, high-performance multifunction DAS card-and other high-precision chemical sensors, which can monitor the concentration changes of CO2, CO, O2, H2S and CH4 in real-time. Visual C++ was employed to develop the real-time data acquisition and display interface, which are useful to display and save or playback curves of real-time data, what's more, intelligent alarm function is also available. This system features simple installation, convenient wire routing and great system stability. Furthermore, the usage of new developed downhole explosion monitoring system provides a safe downhole environment for gas drilling.
Bringing Wireline and Coiled Tubing to New Frontiers on a Light Well Intervention Unit
Authors: Drange C.
Published: July 2010

The paper will discuss the introduction of a new method of completing wells whilst reducing the amount of time spent by rigs on each well drilled.

The information presented in the paper will enable operating companies to rethink their way in which they use their drilling rigs, and allow for more of the completion phase to be performed by lighter services such as coiled tubing and wireline.

Based on this new method of completions, up to 9 days per well can be saved on rigs per well. By utilizing this new method of completing wells, allows coiled tubing and wireline to move into a more dynamic market from a light well intervention vessel with a stiff riser solution.

This paper will explain how the use of coiled tubing and wireline in a much more effective way on subsea wells will increased the income of the operating companies, increase the use of known technology on wells where this has not been available before and explain how this set-up will allow for operations in harsh conditions from light well intervention units.
Ahead of Bit Pore Pressure Prediction using VSP - A Case Study in South China Sea
Authors: Yuhong Xie , Jun Cai , Lingxia Zhen , Hong Tian , Yanhua Li , Voskamp Arne , Bailin Wu
Published: July 2010

Presented in this paper is a case study in South China Sea on formation pore pressure prediction ahead of bit by using a look-ahead vertical seismic profile (VSP). At the intermediate total depth (TD) of 2930m of the study well, wireline logs and VSP data were acquired, and VSP inversion conducted. A pore pressure model was calibrated based on VSP data and validated with the drilling and wireline data above the intermediate TD. The model was then applied to the VSP-inverted velocities below the intermediate TD to predict the pore pressure profile ahead of the bit. Following the successful drilling of the study well to the final TD, a second VSP, wireline logs and formation pore pressure measurements were acquired. The post-drill pore pressure evaluation revealed that the look-ahead pore pressure under-predicted the actual formation pore pressure by a small margin. A number of factors that would improve the accuracy of look-ahead velocity inversion, such as the presence of very low frequency range of the spectrum and application of constrain point(s), have been examined in the paper. Furthermore, it has been demonstrated that undercompaction is not the only overpressure mechanism in this study area, unloading may also have contributed to the overpressure. Both Bowers and Eaton models can be applied to predict pore pressure ahead of bit for the overpressure mechanisms in the area.
Well Test Analysis of Multiple Matrix-to-Fracture Fluid Transfer Fluid Transfer in Fractured-Vuggy Reservoir
Authors: Djatmiko W. , Hansamuit V.
Published: July 2010

This paper describes techniques to identify vugs in a real pressure buildup data. The reservoir under study is an under-saturated carbonate reservoir dominated by vugs and karst. We analyse the 80 hours of pressure buildup following a 100 hour of pressure drawdown. We observe the pressure derivative behavior cannot be described using current NFR models such as dual porosity and triple porosity models. This is because some pressure derivatives are obscured by reservoir boundaries and the matrix-to-fracture fluid transfer does not behave as it were in a multiple porosity reservoir. In this heterogeneous reservoir, we believe this corresponds to the number of matrix inter-porosity flow parameter, and thus degree of reservoir heterogeneity. If we force the data using dual porosity or triple porosity models, the error will be high (>15%), because the pressure derivative cannot follow all the transition periods.

We use combined analytical and numerical methods to tackle this problem. First the dual porosity analytical solution is invoked to estimate the reservoir parameter (ω, λ and k). Next, a numerical triple porosity model is set up to represent the reservoir. The reservoir parameters initially follow analytical results as initial guesses. History matching procedures are performed to compare DST data with the calculated bottom-hole pressure. When these agree, reservoir flow capacity and storage capacity can be determined for fracture, matrix and vug respectively. We found volumes of vug cannot be ignored in a triple porosity system.

This technique can be used to quantify vugs or karst from well testing when analytical dual porosity or triple porosity model are unable to handle all matrix-to-fracture inter-porosity flow due to reservoir heterogeneity. Using this technique, we believe not all well test data in carbonate reservoirs (especially for high k.h) can be analyzed using current analytical models. Ignoring this, the estimated permeability is significantly different from the actual.
Evaluation of Sand Control Completion Alternatives and Asphaltene Deposition Treatments in the Area 2 Sur Field Maracaibo Lake Venezuela
Authors: Vladimir Vasquez C.
Published: July 2010

The main reservoir in the Area 2 Sur field is the Eocene C/VLG-3676, it is a consolidated reservoir located in the Maracaibo Lake (Venezuela), with recoverable reserves of approximately 572 MMSTB; this reservoir is characterized by complex challenges such as high temperature, sand production and asphaltene deposition. This paper provides a methodology to choose the most feasible completion alternative to minimize sand production and asphaltene deposition in this field. Several analyses were made to determine possible causes and solutions of sanding and asphaltene deposition. Also, a number of sand control techniques and asphaltene deposition treatments were technically evaluated to know the feasibility of each option in the field. Sand production wells are located mainly in the North and Central zone of the reservoir while asphaltene deposition it is common in the South region. Five techniques have been applied to minimize sand production, only production rate control has been successful in some regions of the field. Two asphaltene deposition treatments has been used in the field, only clean out have been effective in 60% of the wells applied. Sand production is originated from stresses generated by high production rate which exceed the rock resistance. Asphaltene deposition is because the crude oil composition is unstable, light paraffin and CO2 are present in the gas lift and the reduction of pressure below asphaltene onset flocculation. The optimum gravel size for the field is 8–12 US Mesh and the screen size is 1.25 mm, formation grain size of the reservoir Eocene C/VLG-3676 classify like medium uniform. Slotted liner and production rate control are technically feasible options to minimize sand production in the field. Magnetic treatment and production rate control are suitable to reduce asphaltene precipitation; economic indicators show that the well completion diagrams proposed is economically attractive in all regions of the reservoir.
Propagation of Regular HCl Acids in Carbonate Rocks: The Impact of an In-Situ Gelled Acid Stage
Authors: Gomaa A. M. , Nasr-El-Din H. A.
Published: July 2010

In-situ gelled acids based on polymer have been used in the field for several years, and were used in the field in stages between the regular acids. Literature survey reveals that certain plugging effects within highly permeable layers may occur and result in the diversion of the injected acid into less permeable zones. Recent studies indicated that sometimes diversion was not achieved with a severe damage that can lead to loss the whole well. There is no agreement on when this system can be successfully applied in the field.

Single-stage and multi stage-stages acid test of well performance were conducted using Indiana limestone cores (1.5 in. diameter & 20 in. long) at 250°F. 15 wt% regular HCl and 5 wt% in-situ gelled acid based on Fe(III) as a crosslinker were the acid that used in this study. Propagation of the acid, polymer, and cross-linker inside the long cores was examined for the first time in detail. Stage volume and injection rate, that were the parameters that affect on the propagating of various chemical species, were examined in details. Samples of the core effluent were collected and the concentrations of calcium, cross-linker, and acid were measured. Material balance was conducted to determine the amounts of polymer, and cross-liker that retained in the core.

Experimental results show that In-situ gelled acid should be pumped at low shear rates. In-situ gelled acid at low shear rate conditions instantaneously plugged the tip of the wormhole and didn't create additional wormhole inside the core. Therefore, when the final regular acid stage bypassed the gel, it started to propagate from nearly the last point that the first stage ended. This is to endure proper acid diversion. In-site gelled acid stage volume should not exceed 0.5 PV. No benefits were gained by increasing the volume of in-situ gelled acids. Retention of total iron in the core increased in multi stage acid treatments, especially at low injection rates.
Gas Blowdown Case Study: Striking a Fine Balance in Maximizing Gas Production Plateau and Minimizing Oil Loss: A Case Study of a Gas Blowdown Development Plan for a Mature Clastic Field in Oman
Authors: Garimella Sai , Kalbani Ali , Waili Ibrahim , Kasap Ekrem , Lamki Ali
Published: July 2010

PDO is a major operator in the Middle East with long production history for many of its oil fields. Due to the increased gas supply requirements, it is considering options for blowing down the gas caps of some selected oil fields to cater for the gas demand for achieving sustainable oil production.

The key challenge for these gas blow down is to maximize gas production plateau while simultaneously minimise associated oil recovery losses.

This Case Study illustrates the Gas Blowdown optimisation of a saturated clastic oil reservoir. During the Blowdown Study, optimum gas production rates from each of the Upper and Middle Gharif reservoirs are targeted to meet a given gas production plateau rate. A fit-for-purpose assessment for the impact of subsurface parameter uncertainties on the proposed development demonstrated robustness of the gas production plateau period. This analysis resulted in a Gas production Plateau period ranging from 4 years (Low case) to 7 years (High case) with an expectation case of 6 years.

Multiple Subsurface & Surface development scenarios have been evaluated including lowering pressure ratings for the Separator inlet pressure. The oil & gas production profiles thus generated have been evaluated for robust economics and used for final concept selection & field implementation. Furthermore to minimise oil losses various optimisation efforts have been identified during pre and post blow down phases in terms of re-perforations, gas lift implementation and blow down oriented well and reservoir management practices.

This case study proposes an optimised Gas Blowdown field development by maximizing gas plateau period while minimizing associated oil loss. The Study resulted in selecting the appropriate surface development concept, operating specifications and provided an optimised field management plan during the Blowdown phase. The methodology adopted in this case study should find wider applicability in the industry.
Study of Tracer Test Application for Gas Reservoir Characterization During Underground Gas Storage Process
Authors: Moradi B. , Tahami S. A. , Shariatpanahi S. F.
Published: July 2010

In today's world demand for natural gas as a source of energy has been increased. Especially in Iran the main source of home's heat energy is natural gas. In fall and winter demand for natural gas increases that may exceed the amount of total gas production. Underground gas storage is an activity, which allows to efficiently resolve demand seasonality problems. Natural gas injection and storage in depleted gas reservoirs is a common challenge that overcomes this problem. The aim of this study is to use tracer test method as a way to better understand a gas condensate reservoir to use it as a UGS. Case studies showed that gas tracer technology is one of the best methods for improving reservoir characterization and description of gas storage reservoirs. So it is well known in the petroleum industry that tracer data can provide valuable information on reservoir characteristics and fluid flow performance. The reservoir under study in this work is a limestone gas condensate reservoir with high porosity and good permeability, which is located in south of Iran. Therefore, in order to better characterize the reservoir it was decided to implement tracer test in this reservoir. However, a prerequisite for obtaining reliable information is careful planning, design, and experimental investigation. So different reservoir studies such as geological studies, well logging, and well testing was implemented to describe the reservoir truly. By means of these studies, reservoir operation can be predicted and controlled. In order to find the best tracer and its volume, a comprehensive study on the effects of tracer volume, concentration and adsorption on some plugs was also performs. Finally, it was concluded that Helium is the best tracer for this reservoir, because of its low interaction with rock and fluid and also same velocity with the bulk of fluid flow.
Comparison of Computational Fluid Dynamics of Erosion in Coiled Tubing on Various Wrap Diameters
Authors: Bailey M. , Blanco I. L. , Rosine R. S.
Published: July 2010

Coiled tubing (CT) is widely used in well intervention as a practical and cost-effective means of servicing wells. Since CT's inception, the actual flow through CT has been a point of discussion and theory. Testing has been conducted to study what occurs inside the CT. In recent years, the use of computational fluid dynamics (CFD) software has provided greater insight into actual CT flow patterns, including fluid-flow velocity profiles and secondary flow regimes. CFD helps to understand the fluid-flow phenomenon, which leads to effective application of friction-loss gradients. CFD has proven to be an effective alternative to full-scale testing.

This work compares the results of CFD modeling of internal erosion caused by proppant to actual field data. This paper investigates the increased erosion rates found in the area of tubing that is on the tubing reel during pumping operations. Specifically this paper will investigate how the wrap diameter influences erosion rates as indicated in field data. It compares predicted values, actual values, and computed values from CFD analyses. Results from this work and previous work can be used to correlate a predictive model of erosion rates that can be applied to correct wall-thickness values used in bending fatigue models and force limit calculations. CFD was used to provide correlations for the predictive model without full-scale testing, which greatly reduced the cost of development. Fluids investigated include slurry pumped from an actual job.
Milling Out Plugs in Bakken Horizontal Wells with the Aid of a Coiled Tubing Tractor
Authors: Krueger E. , O’Neal E. , Moore N. B.
Published: July 2010

The Bakken offers the largest potential for technically recoverable reserves in the US; that potential has increased because of new practices utilizing multi stage frac operations. Many Bakken wells have long cased horizontal sections up to 10,000 feet with composite plugs/frac ports set at 500-1000 ft intervals allowing greater fracture uniformity along the producing horizontal section. After frac, current practices dictate that the well must be cleaned and the plugs milled to facilitate maximum future production. This operation has frequently been accomplished using coiled tubing alone. However, the length of the horizontal section of these newer wells frequently results in some plugs being left behind in the well due to CT's inability to perform operations at or near TD. An improvement to current practices would be to utilize a coiled tubing tractor to clean out and mill the remaining plugs past the reach boundaries of CT alone. This new practice was implemented successfully on two wells in the Bakken resulting in fewer plugs (zero plugs in one case) left in the well and increased future production. The case histories of these two wells along with lessons learned are described.
Deliquification of South Texas Gas Wells Using Corrosion Resistant Coiled Tubing: A Six Year Case History
Authors: Poppenhagen K. L. , Harms L. K. , Wilkinson R. , Glover D. E.
Published: July 2010

Running coiled tubing can be an effective tool to deliquify gas wells, but this practice was discontinued in early 2000 in ConocoPhillips Lobo Field in South Texas because of problems experienced due to CO2 corrosion with standard coiled tubing metallurgy. Since 2004, ConocoPhillips has installed 90 corrosion resistant coiled tubing velocity strings as an alternative to conventional carbon steel coiled tubing. These installations have yielded 5 mmcfd in incremental gas rate and the change to a corrosion resistant metallurgy has drastically reduced the high failure rate and costly workovers that resulted from previous carbon steel installations. Various key learnings including candidate selection criteria and future application recommendations will be presented in addition to representative well types and production profiles. Metallurgy comparisons, post-use inspection findings and full-cycle cost implications will also be presented.