bluuebunny/crossref_metadata_2025 huggingface dataset:
A Step Change in Circulating Technology: Increased Efficiency and Cost Reduction Through Simplifying Circulating Sub Technology and Use
Authors: Herrington D.. , Barton S.. , Clausen J.. , Billingsley J..
Published: September 2011

Movement of cuttings produced while drilling is not a new issue to the drilling industry. We do however see the overall depth of wells, as well as their inclusion of extended horizontal runs ever increasing. We find the risk of differential sticking, excessive loss of pressure, and general stuck pipe situations compounded with every foot deeper we drill. The circulating sub has been a long relied upon tool in the drilling world that has aided in the acceleration of cuttings along the annulus towards the surface. When activated they can reduce build-up of debris and cuttings on the low side of the drill string through horizontal runs and in deep and ultra-deep drilling applications by increasing annular velocities. The downside to these tools has always been the constraints of the technology. Various systems for engaging and disengaging circulating subs have been designed over the years, improving on particular points such as actuation, or split flow design, but these designs have consistently relied on fishing out a drop ball or dart to deactivate, or dropping additional balls to cycle the tool. This takes costly time to pump the balls down the string and limits the total number of cycles before the tool must be pulled and serviced, potentially interrupting the run. Service companies have long been searching for a simpler, more efficient method of circulating to the annulus without the lost time and complicated cycling methods required by current technology.

Utilizing a new cycling mechanism design and an open bore (to allow for potential fishing of MWD components), drillers can now cycle an infinite number of times without regard for the tool needing to be pulled due to maximum cycling count being reached. The tool is cycled using a single drop ball and changes in flow rate alone. The tool can be launched with the ball in place, alleviating the need to pump a ball down at all, or the ball can be launched from surface during the run if fishing through the ID is required prior to activating the circulation sub.

This paper details how the development of a step change in circulating technology is assisting a major service company in reducing downtime during the use of the circulating tools in hole. This design has proven easier to operate and has reduced the overall time lost struggling with current tool designs. Supporting case studies are included to detail the increase in efficiency and reduction in costs.
First Successful Coiled-Tubing Intervention Operation on the Helideck of a Normally Unmanned Installation in Offshore India
Authors: Savenkova A. , Turner A. , Lawson K.
Published: September 2011

This paper describes the challenges involved with providing a coiled-tubing (CT) intervention solution from the helideck of a normally unmanned installation (NUI) in the Gulf of Cambay in offshore India.

The project began with a detailed analysis to determine if intervention was practical from the helideck of the NUI, or if barge support or a full jackup-rig intervention was necessary. Some factors in this analysis included the limited deck space, restricted crane capacity, and the existing available utilities. This led to the planning and sourcing of suitable CT, flowback equipment, nitrogen, and fluid-pumping equipment, as well as necessary downhole tools. Trials were performed onshore to optimize the rigup, stackup, and deck layout. The boat loading and lifting plans were created from these trials. The combination of the prejob planning and the trials led to the confidence to conduct this intervention with modified safety arrangements required for the platform when no helicopter operations could be performed.

The purpose of the actual intervention was to complete sand cleanout of the horizontal-well section, isolate the lower oil-producing zone, open a sliding sleeve to access the upper zone, and unload the well with nitrogen to restore production.

This paper also includes the variety of applied technologies that were either attempted or successfully used to bring the well back into production. This required the use of the latest generation of horizontal, downhole-tool solutions, slickline tractors, CT-tool deployment, and contingency operations, which involved a wide range of downhole tools. The results from the intervention and the lessons learned are presented.
HWO/Snubbing Unit Used Effectively for Subsea Flowline Fishing and Cleanout at Nansen Spar
Authors: Ford J. D. , McDaniel R. , Barbee G. P.
Published: September 2011

This paper discusses the prejob research and eventual use of a hydraulic workover (HWO)/snubbing unit for a subsea flowline intervention at the Nansen Spar in the Gulf of Mexico (GOM). Located in a water depth of 3,670 ft (1119 m), the Nansen Spar has been in production since 2002 (Fig. 1). In 2005, a number of umbilical lines became plugged, preventing further chemical injection to prohibit hydrate and paraffin buildup. In 2009, a hydrate blockage formed in a production flowline during the course of an unplanned shut in. Initially, it was decided to perform a coiled tubing (CT) intervention to enter the flexible riser and flowline, clean out the paraffin, and remove the hydrate deposit. During the CT intervention, the pipe became stuck, thereby requiring a fishing operation. At that time, the decision was made to use a 340K hydraulic HWO/snubbing unit to fish the CT and clean out the remaining paraffin and hydrate bridges. The execution and outcome of the fishing and cleanout operation are discussed, as well as some of the challenges associated with not only working in deep water, but through a flexible riser as well. Recommendations based on the lessons learned during the planning and execution of the operation are also presented.
Bayesian Optimization Algorithm Applied to Uncertainty Quantification
Authors: Abdollahzadeh Asaad , Reynolds Alan , Christie Mike , Corne David , Davies Brian , Williams Glyn
Published: September 2011

Prudent decision making in subsurface assets requires reservoir uncertainty quantification. In a typical uncertainty quantification study, reservoir models must be updated using the observed response from the reservoir via a process known as history matching. This involves solving an inverse problem, finding reservoir models that produce, under simulation, a similar response to that of the real reservoir, requiring multiple expensive multiphase flow simulations. Thus uncertainty quantification studies employ optimization techniques to find acceptable models to be used in prediction. Different optimization algorithms and search strategies are presented in the literature, but they are generally unsatisfactory due to slow convergence to the optimal regions of the global search space, and, more importantly, failure in finding multiple acceptable reservoir models. In this context, a new approach is offered by Estimation of Distribution Algorithms (EDAs). EDAs are population-based algorithms, which use probability models to estimate the probability distribution of promising solutions, and then to generate new candidate solutions.

This paper explores the application of EDAs including univariate and multivariate models. We discuss two histogram-based univariate models, and one multivariate model, Bayesian Optimization Algorithm (BOA), which employs Bayesian Networks for modelling. By considering possible interactions between variables and exploiting explicitly stored knowledge of such interactions, EDA can accelerate the search process, while preserving search diversity. Unlike most existing approaches applied to uncertainty quantification, the Bayesian Network allows BOA to build solutions using flexible rules learned from the models obtained, rather than fixed rules, leading to better solutions and improved convergence. BOA is naturally suited to finding good solutions in complex high-dimensional spaces, such as those typical in reservoir uncertainty quantification.

We demonstrate the effectiveness of EDA by applying to the well-known synthetic PUNQ-S3 case with multiple wells. This allows us to verify the methodology in a well controlled case. Results show better estimation of uncertainty when compared to some other traditional population-based algorithms.
Interpreting Azimuthal Propagation Resistivity: A Paradigm Shift
Authors: Pitcher Jason , Bittar Michael , Hinz David , Knutson Craig , Cook Robert
Published: September 2011

In recent years, new advanced resistivity sensors have appeared in the toolboxes of logging-while-drilling (LWD) vendors. These sensors are designed for optimal well placement and accurate formation evaluation and have had a very rapid acceptance by the industry. However, their interpretation techniques and their full capability have not been fully explored or explained.

Geoscientists who use these new sensors must be able to understand and interpret the sensor responses in complex geology and in a wide range of reservoir and formation conditions. By fully examining and using the responses of these sensors with the aid of appropriate modeling tools, a much clearer insight into the rocks surrounding the wellbore can be gained. The fundamental petrophysical characteristics and geometries of the rocks can be evaluated, and the boundaries surrounding the borehole can be understood.

This paper describes the fundamental physics of the sensors, as well as many interpretation techniques. Interpretation workflows are presented to address various petrophysical concerns and methods. This paper also explains the planning, geosteering, and formation evaluation of a typical well with this new technology. Benefits and limitations, lessons learned, pitfalls, and best practices are also discussed. Finally, the paper includes field examples to show the usefulness of this new technology for well placement and formation evaluation in various types of hydrocarbon reservoirs.
Innovative Use of Inflatable Packer and ROV To De-Oil Damaged Subsea Pipeline: Case Histories
Authors: Murphy R. A. , Neves S.
Published: September 2011

When a well is abandoned the flow line contains well effluent which must be recovered before abandonment is completed -this can present problems, especially in deepwater sub sea wells. In a well in the Campos Basin, Offshore Brazil, in a water depth of 624 meters (2067 ft.), pigs were pumped from the wellhead to the production facility to flush the flexible line, however they became stuck leaving some 1400 meters (4593 ft.) of 4 inch ID flow line filled with production fluid. To clean the balance of the flow line it was decided to cut the line downstream of the pigs and insert a flexible deployment flow line from surface to seal inside the cut and thereby facilitate the continued displacement of the flow line. It was agreed that the use of an inflatable packer deployed by a Remote Operating Vehicle (ROV) would offer the best chance of success, however two problems existed which could affect the adequate sealing of the packer element:

• The ID of the flexible flow line contained a continuous spiral groove 1/16inch deep.

• The sea floor temperature at the mud line was 39°F.

To evaluate this, lab tests were initiated and successfully performed to confirm viability of the seal in this situation. The packer was then made up with a 1″ hose to a 4″ ID flexible deployment line located on a work barge, run to bottom and inserted into the flow line cut using the ROV. It was set, the setting plug sheared and 862bbls of sea water were pumped through the line to clean it out. Upon completion of the job the packer was left in place and recovered along with the flow line.

In this paper the authors will describe the testing of the concept, its subsequent successful use with the ROV and the problems which were encountered with inserting the packer into the flow line. They will go on to describe two further such operations in which the lessons learned from the first operation were taken into account. All the operations were successful, allowing recovery and subsequent reuse of the flow lines.
High-Temperature Downhole Motor Facilitates Cleanout of Obstructed Thermal Well, Saving Production Downtime
Authors: Thompson J. , Rossing M.
Published: September 2011

Certain wells in the Peace River region of Alberta, Canada, produce heavy crude oil along with H2S and CO2. The heavy crude oil is normally recovered with enhanced production methods involving thermal wells whereby the crude is heated to very high temperatures to facilitate production. One such well became plugged by scale deposits and efforts were made to clean out the obstruction using coiled tubing (CT) intervention techniques. However attempts to do so with jetting tools and acidisation proved to be ineffective and the only alternative left was to run a mill with a downhole motor. A major problem was posed by the bottomhole temperature of 300° C (572°F) which precluded the use of standard motors. The operator was thus faced with the probability of having to make an extended shut down to allow the well temperature to decline to an operable temperature level where standard equipment could be used, or look to alternatives.

In an attempt to avoid this extended downtime it was decided to run a non elastomeric high temperature downhole motor, which uses a positive displacement principle with a stainless steel stator and rotor system with no elastomers, which as a result is rated to 260°C (500°F). The 2-7/8″ OD motor was run with a 3-9/16″ OD mill on 2″ OD CT to try to mill out the obstruction in the 4-1/2″ slotted liner while circulating KCl fluid at the rate of 50 litres/min (13gallons/min) and Nitrogen at 30 standard cubic meters/min (1100 standard cubic feet/min). The obstruction was encountered at 820.6 meters (2,692ft) and successfully milled to 929m (3048ft) where the mill broke through and was run to bottom at 945m (3100ft) to circulate clean before pulling out. The whole operation took a total of 9 hours.

In this paper the authors will review the well conditions and the motor design and explain the decision to run it at downhole temperatures in excess of its rating. They will go on to detail the milling operation which was successful in returning the well to production at a considerable saving in production downtime when compared to the available alternatives.
New Innovative Top-Side Solutions To Provide Beneficial Offshore Well Intervention
Authors: Torgersen K. I.
Published: September 2011

Oil reserves being more and more expensive to develop, which makes it more and more important and beneficial increasing oil recovery on existing fields. To do so, drilling of new wells and side tracks are done, but taking care of existing wells, keeping them healthy and optimum producing, is often the most beneficial method for increased oil recovery.

This paper will focus on what can be done to increase benefit by doing cost efficient well interventions, at the same time as HSE measures are improved, on offshore installations and vessels. The paper will highlight the IOR issue, the potential for increased well intervention work, and focus on what we can do to make this happen.

The paper will present solutions for well intervention from existing well head platforms with or without drilling rigs, and for subsea wells. For existing platforms with drilling rigs, the potential for working in parallel will be described. For subsea wells, main focus will be the increasing need and the limited number of floating rigs, and how we can sort this out in a cost-efficient manner.

Traditional thinking have more or less been: what can we do with what we have - now it must be changed to: what do we need to achieve best results? Main intention with this paper will be to engage oil- and service- companies to innovative IOR thinking, and for inspiration the paper will include some examples of what has been both possible and beneficial.
Coiled Tubing Milling Operations: Successful Application of an Innovative Variable-Water Hammer Extended-Reach BHA to Improve End Load Efficiencies of a PDM in Horizontal Wells
Authors: Castaneda J. C. , Schneider C. E. , Brunskill D.
Published: September 2011

Horizontal completions continue to increase in popularity throughout the industry. In North America the majority of horizontal wells are drilled in shale gas formations. These formations require fracture stimulation for economic production. The majority of these stimulations are completed by fracturing four to six clusters of perforations simultaneously at high rates followed by a mechanical isolation with a composite bridge plug. As the horizontal wells increase in length the number of plugs required increases, with up to twenty plugs not being uncommon. These plugs are removed with a positive displacement motor (PDM) and mill run on either coiled tubing (CT) or jointed pipe. In longer-reach horizontal completions, plug removal using CT becomes more challenging as the efficiency of surface end loads transmitted to the mill are reduced. Quite often the deepest plugs can not be reached with standard coiled tubing, instead requiring larger-diameter, more costly, coiled tubing or jointed pipe. The need to extend the operating depth to effectively operate PDMs and reach the deepest plugs has led to development of several tool systems.

This paper will discuss the engineering, design, testing and initial field trial results of a variable fluid hammer extended-reach tool; how it was used to improve plug milling performance, to give superior control of weight on bit, to extend coiled tubing reach in the horizontal section and to reduce operational time. These field results will be compared with results using other methods of friction reduction, such as pipe-on-pipe friction reducers.
Coiled-Tubing-Conveyed Perforating in Shale
Authors: LaGrange T. , Barton J. , Andrich L.
Published: September 2011

This is a study of the development and ultimate use of the CT (Coiled Tubing) Firing Transfer System used in three different scenarios and is a comprehensive examination of what specifically is required for use and the contrast between past and present methods in order to quantify perforating efficiency. The Coiled-Tubing-Conveyed CT Firing Transfer System has greatly improved Coiled Tubing perforating efficiencies when multiple zones are to be perforated during a single run in a well. Cost, capability and time, (cost of time) have always been limiting factors in bringing oil or gas to market profitably. The CT Firing Transfer System has been used in many hundreds of wells. An estimated 15,700 individual CT Firing Transfer Systems and perforating guns have fired over 90,000 perforating charges with a very high degree of reliability. The savings at the well site are substantial in direct imbedded equipment and maintenance costs savings to the end user over a period of just 3 years. The simplicity and methods of its use in many different scenarios have been developed and are in use successfully. Although originally developed for Coiled Tubing, the CT Firing Transfer System has also been used for Tubing Conveyed Perforating (TCP) applications.
Light Well Intervention Scale Milling Enables Reservoir Access
Authors: Larkins B. M. , Mitchell D. A.
Published: September 2011

This paper will present a record North Sea electric line milling operation carried out during March 2010, the success of which enabled access to the reservoir section, with subsequent interventions leading to a significant uplift in production.

The Operator was experiencing high water cut in one of its wells; previous interventions in other wells connected to the same reservoir indicated a high probability of scale. The plan was to log, isolate the watered out zone and then re-perforate in order to increase oil production rate. Electric line Tractor Milling equipment was mobilised as contingency, should well access be an issue, which happened to be the case.

In order to keep the bit clear during milling, cuttings were flowed back to surface. Progress was made until the surface choke packed off and flow was no longer achievable, the toolstring had to be retrieved whilst choke and lines were cleared. The scale sheath was eventually broached and the decision made to continue in hole in order to drift, as well as providing the capability of dealing with any further scale that may be present; the Tractor Miller was started once more with a minimum of resistance encountered. Target depth was attained, all Tools were then retrieved to surface with no issues.

The overall objective was achieved, resulting in a significant increase in production. One hundred and twenty one (121 metres, 390 feet) of calcium carbonate scale was removed during the operation, validating the use of light well intervention techniques when removing scale.

This paper will discuss the technical aspects of e-line milling and challenges overcome during this particular operation.
Debris Management System for Pressure-Controlled Wellbore Drilling and Intervention Operations
Authors: DeMong K. , King G. E. , Odegard S.
Published: September 2011

In shale gas horizontal wells with multiple intervals completed, the predominant completions method has been multistage fracturing while plugging with drillable bridge plugs and jet perforating the cemented casing. Typically the bridge plugs are drilled out under pressure with coiled tubing. The ability to optimize drilling/milling parameters while drilling out with pressurized coiled tubing has been hampered by the lack of information in the coiled tubing cab about the speed that debris is generated, the size of debris generated, and whether the circulation fluid properties and rate are sufficient to remove the debris from the hole. In response to dealing with challenges of drilling out bridge plugs and performing other pressurized intervention work in long horizontals, a new surface debris management system was developed and successfully tested. Using the new system, a clearer picture emerges regarding the conditions being created down hole. This system has aided in optimizing drilling and circulating parameters and has resulted in faster bridge plug drill outs, cleaner casing and fewer drilling and intervention problems.
Modelling of Depletion-Induced Microseismic Events by Coupled Reservoir Simulation: Application to Valhall Field
Authors: Zhang Xing , Koutsabeloulis Nick , Kristiansen Tron , Heffer Kes , Main Ian , Greenhough John , Hussein Assef Mohamad
Published: September 2011

Reservoir depletion/injection results in changes in effective stress, which may cause formation failure, propagation of existing fractures/faults and initialisation of new fractures/faults. A flow-deformation coupled reservoir geomechanical modelling approach has been applied to compute the change in reservoir effective stress and associated propagation of fractures and reactivation of faults. The computed inelastic strain change was used to predict the magnitudes of microseismic emissions associated with fault reactivations. The moment magnitude of microseismic events, consistent with the Richter scale, can be computed from the scalar value of their moment tensor. In a discontinuous model, the moment tensor can be calculated directly; in finite element models, the moment tensor is calculated by integrating the change in inelastic shear strain over the volume of the elements containing the failed fault.

Coupled 3D geomechanical (deformation and fluid flow) simulations for Valhall field were conducted. Well rate and reservoir pressure histories were used as inputs to simulate reservoir depletion/injection. The 99 faults visible on seismic interpretations and 22 subregional fracture sets were included in the model. An elasto-inelastic cap model including water-weakening mechanism was used to model the chalk reservoir; the failure of faults and fractures were simulated by Mohr-Coulomb criterion. Prior to performing production simulation, preproduction stress modelling was carried out to reach an equilibrium stress state that was consistent with the in-situ condition, in terms of magnitude and orientation. Then, oil production at 112 wells and water injection at 15 wells for the period from 1982 to 2006 were simulated, during which the simulated microseismic events were in a good agreement with observations. The computed formation deformation in the reservoir and overburden was related to the in situ stress and faulting structure and was correlated over long distances. These characteristics are indicative of a near-critical process (and are also observed in flow rate correlations in the field). The coupled 3D geomechanical simulation provides a tool for validating modelled reservoir geomechanical effects against specific field data, and so enhances confidence in the implications predicted for drilling operations and reservoir management.
An Analytical Method for Predicting the Performance of Gravitationally-Unstable Flow in Porous Media
Authors: Farajzadeh R. , Meulenbroek B. , Bruining J.
Published: September 2011

In this paper we follow a similar procedure as proposed by Koval (1963) to analytically model the performance of gravitationally unstable flow in porous media. The Koval model is analogous to the Buckley-Leverett method and multiplies the heterogeneity index of the system as an input (H-factor) with the fluid-flow (here gravity) induced instability factor, E to obtain the Koval factor KG = HE. This paper only considers the gravity induced instability factor E (H=1). The Koval factor is implemented in a modified fractional flow function that includes a dilution effect when the CO2 moves away from the interface to describe countercurrent gravity flow. The pseudo two-phase flow problem provides the average concentration of CO2 in the brine as a function of distance. The KG-factor can be used in commercial simulators to account for the density-driven natural convection, which cannot be currently captured because the grid cells are typically orders of magnitude larger than the wavelength of the initial fingers. Such natural convection effects occur in storage of greenhouse gases in aquifers and EOR processes using carbon dioxide or other solvents.

A comparison of the analytical model with the horizontally-averaged concentrations obtained from 2-D numerical simulations provides a correlation for calculation of the KG-factor for different Rayleigh numbers. The model shows a rarefaction followed by shock-like behavior because the CO2 concentration decreases away from the gaseous CO2-liquid interface. The agreement between the analytical model and full numerical simulation is practically acceptable. We leave the introduction of the heterogeneity factor for future work.
Application of Toe-to-Heel Air Injection (THAI) Process in Fractured Carbonate Systems: 3D Simulation of the Effect of Fractures Geometrical Properties, Reservoir and Operational Parameters
Authors: Fatemi S. Mobeen , Ghotbi Cyrus , Kharrat Riyaz , Badakhshan Amir
Published: September 2011

Toe-to-Heel Air Injection (THAI) Technology, a new heavy oil recovery process to overcome Conventional Fire Flooding (CFF) defects, has been studied on non-fractured sandstone models and is found a promising Enhanced Oil Recovery (EOR) method for certain heavy oil reservoirs, but its applicability on fractured carbonate heavy oil reservoirs, such as those in Middle East, remained questionable. The objective of this paper was to evaluate the effect of fractures geometrical parameters such as fracture density, orientation and networking on the THAI process performance for a low permeable naturally fractured carbonate heavy oil reservoir in Persian Gulf coast namely "Kuh-E-Mond". To approach the problem, a combustion tube test using field crude oil and crushed carbonated rock performed and numerical model developed and validated according to the experimental results. Validated model modified to 3D to investigate the performance of THAI. THAI performance was studied in conventional and fractured models consisting fractures in Between Wells Region (BWR), Horizontal Well Region (HWR), vertical, horizontal and networked fractures. Ultimate oil recovery and recovery rate decreased in all fractured models as compared to the conventional case. Higher traversal fractures density reduced ultimate oil recovery. Near injector traversal fractures have less disastrous effect on the process performance. In the case of networked fractures (presence of both longitudinal and traversal fractures), accompany of longitudinal fractures enhanced the recovery achievable in the case of traversal fractures. Simulation results showed that THAI is more applicable on highly networked fractured reservoirs such as those occur in Middle East compare to lower density fractured reservoirs
A New Model for Predicting Water Cut in Oil Reservoirs
Authors: Kewen Li , Yangtze U. , Xianghai Ren , Yangtze U. , Li Li , Xiaodong Fan
Published: September 2011

Water cut is an important parameter in reservoir engineering. For example, water cut data may be used for the estimation of reserves and ultimate oil recovery as well as reservoir surveillance and management. However it is difficult to predict water cut in water flooding reservoirs. Simulation technique could be used to forecast the water production, but it is time consuming, expensive, and often require information that is not readily available. Fractional flow analysis can easily be conducted using only a spreadsheet. However, most of the traditional models represent water cut as a function of cumulative oil production instead of production time. Note that cumulative oil production itself needs to be estimated or predicted. To this end, we derived a new model that correlates water cut and production time in oil reservoirs. It is easier to predict water production and estimate the performance as a function of production time when using this new model than when using traditional ones. The proposed model has been tested using production data from many oil wells and several reservoirs with a wide permeability range. The results have demonstrated that the proposed new model works satisfactorily in most of the cases studied.
Experimental Study of Water Shut-Off by Wettability Alteration to Gas Wetness
Authors: Li Kewen , Yangtze U. , Zhang Haoping , Peking U.
Published: September 2011

Gas wells may suffer significant decline in gas production or even get killed because of the water invasion into production zones. Closing off the water producing zone may not be acceptable in many cases. In this study, the feasibility of reducing the water production in gas wells by changing the wettability of the gas zone from preferential water- to gas-wetness using fluorine carbon surfactant has been investigated experimentally. The basic mechanism was that the entry capillary pressure has to be overcome prior to water entering the gas zone. Naturally water can imbibe into gas zones spontaneously because the rock in gas zones is water wet, most probably. After the wettability alteration from water- to gas-wetness, water cannot enter into gas zones if the differential pressure is less than the entry capillary pressure and the water flux will be significantly reduced even if the differential pressure is greater than the entry capillary pressure. An artificially made, consolidated two-layer core model was used to conduct the study. The two layers had different permeability and the top layer was served as the gas zone and the bottom layer served as the bottom aquifer. The gas production was measured at different initial water saturations with and without wettability alteration from preferential water- to gas-wetness in gas zone. The experimental results showed that the water breakthrough time could be postponed and that the amount of water invaded into the gas zone could be reduced significantly by altering the wettability of the gas zone to gas wetness. The advantages of this approach to reducing water production were: 1) the permeability of the gas zone was not affected notably by the chemical treatment for wettability alteration; 2) the chemical treatment for wettability alteration had great longevity.
Combining Experimental Design with Proxy Derived Sensitivities to Improve Convergence Rates in Seismic History Matching
Authors: Arwini Saleh , Stephen Karl D.
Published: September 2011

An assisted history matching method has been developed where simulations are quantitatively compared to observed 4D seismic and production data and then updated in an objective manner. The approach uses experimental design to initialise a stochastic parameter search but also to derive a proxy model of the misfit between observations and predictions. The proxy model is then used to guide the stochastic search algorithm to speed up convergence. Updating of the proxy model periodically during the search improves convergence further.

The approach was applied to the Schiehallion UKCS field where we use 6 years of production along with six 4D seismic surveys. The proxy model, a quadratic regression equation, was derived for the combined misfit of both production and seismic data. Transmissibility of a number of barriers and faults as well as permeability and net:gross (NTG) were modified to improve the history match.

The approach improves the efficiency of finding the best models. Experimental design reduces the number of models to initialise the stochastic approach by a factor of 10. Continuous updating of the proxy not only leads to three times faster convergence but also enables better models to be found. History matching without experimental design or proxy derived gradients reduced the production misfit by sixty six percent while our new method gained a further ten percent reduction. We improved the exploitation of misfit information without compromising exploration of the parameters.

History matching is a very important activity during the development and management of petroleum reservoirs. Obtaining matched models is fundamental to ensure reliable future forecasts, and give an improved understanding of the geological description and the dynamic behaviour. Improved recovery factors can then be achieved by accurately locating infill wells and maintaining production longer.
The Potential of Smart Well Solutions for the Development of Thin Oil Rims during Gas Condensate Production in the Yamal Region of Russia
Authors: Fayzullin M. F. , Nasibullin A. Z. , Yazkov A. V.
Published: September 2011

The paper focuses on the simulation case study of smart technologies for horizontal wells for the development of thin oil rims in the center of Russian gas condensate production.

Operating companies worldwide are turning to intelligent completions to mitigate the consequences of uneven drawdown and reservoir heterogeneity along the wellbore. The proposed enhancements have proved its applicability to increase oil-part profitability of the highly productive formations offshore Africa and the North Sea. Following recent completion advances, the oil rims common in the Yamal region of Russia could be good candidates to be smart instead traditional well interventions which may be more costly or ineffective.

We describe a systematic workflow that can be used to evaluate the viability of such technologies, specifically in thin oil rims. The intent then is to improve oil recovery at the simultaneous production from oil and gas zones. We analyze a number of horizontal well completion designs with stingers and ICV by means of simulation models. The models consist of a multisegment well option from a commercial software program. The ICV simulation, compared with models of conventional reduced well designs, predicted an additional 2–3% of oil recovery over 10 years. Additionally, it also indicates CAPEX would be 5-7 times more and operating risks are much greater. Summarizing, the results showed current limitations and effects of each smart solution but also forced us to consider production on the supercritical gas rate modes: naturally flowing production with gas breakthroughs controlled at the wellhead. Finally, the economic and risk screening criteria are introduced pointing to the optimum recommendations for development decisions.
Estimation of Multiple Petrophysical Parameters for the PUNQ-S3 Model Using Ensemble-Based History Matching
Authors: Li Heng , Yang Daoyong
Published: September 2011

Reservoir simulation and modeling remains a cost-effective tool to characterize geological structure, determine fluid saturation, and optimize reservoir performance. In spite of extensive research work, it remains a challenge to generate multiple reservoir models conditional to static and dynamic data that represent a correct sampling of the true posterior probability density function. Although many challenges remain, the ensemble Kalman filter (EnKF) technique has recently been proved to be an efficient data assimilation method and successfully used in assisted history matching for estimating reservoir petrophysical parameters, such as porosity, absolute and relative permeability, and fluid-contact depth. Few attempts have been made to study impacts of simultaneously tuning multiple parameters on the estimation results. In this study, the ensemble-based history matching has been successfully applied to simultaneously estimate multiple petrophysical parameters for the PUNQ-S3 model. More specifically, the selected tuning petrophysical properties include horizontal and vertical permeability, porosity and three-phase relative permeability curves. Four data assimilation scenarios with different combination of the tuning parameters have been evaluated. The ensemble-based history matching technique is found to be capable of estimating multiple petrophysical parameters by conditioning the reservoir geological models to production history. The uncertainty range of production data generated from the updated models is reduced compared to that of initial models. However, the history-matched models may not always provide good production prediction results, especially when absolute permeability and relative permeability are tuned simultaneously. This further illustrates the non-uniqueness of the history matching solutions. In addition, for the PUNQ-S3 case examined in this study, three-phase relative permeability curves can be estimated with good accuracy when absolute permeability fields are known.
Relative Permeability Prediction from Image Analysis of Thin Sections
Authors: Hossain Zakir
Published: September 2011

The objective of this study is to define the physical basis approach to calculate relative permeability of reservoir rocks from image analysis of thin section. Relative permeability is one of the most important parameter and widely used for reservoir characterization. Relative permeability is only measured in the laboratory. To measure relative permeability in the laboratory are expensive and time consuming. Alternatively relative permeability may be estimated from numerical methods such as Lattice-Boltzmann and network modeling. To applying the all method need lot of computational effort and the physical justification of relative permeability estimation remains hidden. A simple and powerful equation to estimate the absolute permeability from porosity and specific surface area is the Kozeny’s equation. Darcy’s assumption was applied to Kozeny’s equation to calculate relative permeability of two phase-fluid flow without introducing any empirical factor. Numerical simulation and image analysis processing technique were applied to check the consistency of Kozeny’s approximated relative permeability model. Relative permeability predicted from Kozeny’s approximation was compared with permeability predicted from Lattice-Boltzmann flow simulation as well as with laboratory measured data. Relative permeability predicted from numerical simulation and image analysis techniques are well agreed with permeability predicted from Kozeny’s approximation. Relative permeability predicted from Kozeny’s approximation are also comparable with permeability predicted from Lattice-Boltzmann flow simulation as well as with laboratory measured data. Given permeability model in this study is the physical basis approach and may used to calculated relative permeability from image analysis of thin section.
Reversible Platform
Authors: Christino F.. , Costa B.. , Jacinto A.. , Melo M.. , Pereira O.. , Schlüter H..
Published: September 2011

This paper presents a way to adjust an oil production offshore platform unit, specifically its liquid processing plants, to the new conditions of production that appear throughout the productive life of an oil field. For in such a way, due to the increase the amounts of water and decrease of produced oil, equipments, firstly, destined to the oil treatment can be converted into equipment for water treatment. In this way the connections between such equipments are modified in order to be adjusted to the new situation.

This invention, witch is the subject of a Brazilian Patent Application, can be useful to adequacy an oil offshore platform to its actual situation, i. e. when the produced water flow increase much more than its water treatment facilities. In this way we can debottleneck the produced water treatment system prevent closing the wells and, even so, boost the oil production. The invention can also be applied in new projects, in order to prevent such future difficulties.

As a results among, approximately, twenty platforms we've already been on board 80% of them was identified in such conditions, i. e, they are closing well and losing oil production, so we can do the modifications just now. Moreover we identify a situation where, just doing little arrangements, it will be not necessary to operate one of them (a semi submersible unit with a180 000 bpd capacity). It could be moved to another field to produce oil.

We must highlight that the proposal presented seems to be simple, but it is extremely advantageous, since it makes possible to adjust an installation in operation to a not foreseen situation of fluid treatment.

As a conclusion this methodology is mainly appropriated to a mature field optimization.

As a Significance of Subject Matter we can register that with these procedures it is possible to keep and, most of the time, increase the oil production and, moreover, to increase the platform's live.
Innovative Combination of Dynamic Underbalanced Perforating with Emulsified Acid and Non-Damaging Viscoelastic Surfactant-Based Fluids Boost Productivity in Low-Permeability Naturally-Fractured Carbonates
Authors: Cesin S.. , Fayard A.. , Camarillo J.. , Lian E.. , Flores J.. , Flores P. Tejeda , Mendo A. Rosas
Published: September 2011

The fields in southeastern Mexico have produced from Cretaceous and Jurassic-age naturally-fractured carbonate reservoirs since the early 1970s. Many recent exploratory wells drilled and completed in these high-pressure, high-temperature formations have yielded unsatisfactory results due to a combination of causes, including severe drilling-induced formation damage to low-matrix permeability reservoirs. Conventional completion and stimulation treatments to remove and bypass the damage have yielded satisfactory results in some cases but not in others. To increase productivity from new discoveries, an integrated approach to the completion and stimulation of low-permeability naturally-fractured carbonate reservoirs is proposed.

An innovative technique, combining dynamic under-balanced perforating with a highly-stable emulsified acid and a non-damaging viscoelastic surfactant-based acid, is presented in this paper. Three successful applications in southeastern Mexico are documented, including a low-productivity development well; a well originally perforated and stimulated using conventional technology; and an exploratory well, resulting in substantial production increases in all three cases. These applications served to prove that the combined effect of the proposed completion and stimulation technologies was the enabler to achieve superior production results. The highly-retarded emulsified acid pumped through clean perforating tunnels produces longer fracture penetrations, positively impacting the performance of low-permeability reservoirs and resulting in improved production responses. At the same time, the viscoelastic system reduces leakoff, which is necessary to extend fracture lengths further in the reservoir. The fluids combined in a high-rate pumping technique that consisted of alternating stages of emulsified acid, main acid, and diverter reduced the creation of wormholes near the wellbore, thus increasing the penetration of the treatment in the reservoir.
Operators Gain Significant Operational and Safety Gains with Remote Data Acquisition and Virtual Rig Presence
Authors: Cannon Katherine , Clarke Kieran , Muhi Namir , Davies Jonathan
Published: September 2011

Today's exploration and production operations in offshore environments face increasing limitations on bed space and restricted evacuation capability. Manning operations the traditional way is no longer an option. Remote operations pose a feasible alternative which brings equally important additional benefits. This paper describes the technical and personnel considerations of developing and deploying a remanned solution for wellsites and also reviews the challenges and successes of doing so as a standard approach to wellsite operations with specific emphasis on remote data acquisition and monitoring.

Remanning can occur in varying degrees from remote data gathering to expert assistance of wellsite personnel, through personnel reduction up to complete removal. A case study for remanned data aquisition in Asia Pacific is analyzed. This deployment required the complete removal of mudlogging staff from the wellsite. This paper details the changes in roles and responsibilities, re-engineering of processes and challenges overcome which led to a successful implementation.

The implementation of a remote data aquisition service was a complete success. Virtual-presence of data engineers via integrated video and radio over intranet solutions and implementation of VPN solutions using advances in communications technology allowed optimum use of globally distributed expertise. These solutions provided the operator with significant additional benefits. Mudlogging rig footprint was reduced to zero while improving service quality through real-time decision making and instant geosciences analysis. Operational cost savings with reduced travel and support costs were achieved, in addition to the expected reduction in HS&E exposure.

The current emphasis on remote monitoring, support and data recording capabilities allied with pressure from operators and regulators to remotely deliver O&G services and increasing speeds of developing ICT. We can expect to see a dramatic shift in the traditional way of providing wellsite services. Remanning is an effective solution that has proven its capability; however, is still only implemented sparingly. With a focus on safety and efficiency, virtual staffing will become the standard over the coming years; here we include some of the furture developments that will need to be achieved to make this a reality.