bluuebunny/crossref_metadata_2025 huggingface dataset:
Low-Rate Fracture Treatment in the Bakken Shale Using State-of-the-Art Hybrid Coiled-Tubing System
Authors: McNeil Fraser , Harbolt William , Bivens Eric , Lindsay Sharlene , Paterniti Melanie
Published: September 2011

In low-permeability formations, natural fractures, fissures, and other geologic heterogeneities are important considerations in the design of hydraulic-fracture treatments. In some formations, it is considered beneficial to capitalize on these conduits to establish a greater network of connection to the reservoir. In the Bakken shale, near Westby, Montana, a simple planar fracture was desired because complex fracture growth could result in connectivity to a zone of nonproductive interest and led to the following issues:

Higher rates, which could result in extreme fracture complexity and limited fracture extension. Inability to effectively place proppant for conductivity. Excessive fluid leakoff caused by high net pressures requiring large pad volumes. Connection to water-producing zone. Less aggressive proppant schedule because of likelihood of screenout. Increased cost, footprint, personnel, and equipment on location.

With an understanding of the formation-rock properties, stresses, and the natural fracture system, the treatment design parameters were established to help ensure lower treatment pressures and optimum fracture extension in the zone of interest. This paper presents the successful execution of a multi-interval fracture-stimulation treatment for a long-lateral horizontal completion in the Bakken shale using a state-of-the-art hybrid coiled-tubing (CT) system and hydrajet-assisted fracturing (HJAF) technology. The new approach incorporated the following technology:

Low-rate treatment schedule. Multiple-fracture stimulation treatment. Aggressive proppant-treatment schedule. Higher gel viscosity to encourage desired fracture growth and proppant transport. Hydrajet perforating. Dynamic fluid diversion to isolate treatment to intended zone. State-of-the-art hybrid CT system.
Water Injection Enhancement through a Novel Oil-Soluble/Water-Dispersible Combination Cleaner and Corrosion Inhibitor
Authors: Hilfiger M. G. , Stewart S. A. , Ansari A. M.
Published: September 2011

A novel oil-soluble/water-dispersible combination cleaner and corrosion inhibitor was developed. It is designed to be applied in water injection lines to clean deposits, inhibit the formation of future deposits and provide protection from corrosion. This chemistry is especially effective against paraffinic/hydrocarbon deposits, which can help hold together scale such as iron sulfides and help them adhere to the pipe walls, filters, and increase downhole plugging. Evaluation of deposits from various field locations in North America was performed via bottle shaking dispersion studies. The amount of hydrocarbon uptake into the water phase was measured through the use of fluorimetry. Our testing clearly reveals the ability of the product to break down these deposits over time and prevent re-adhesion onto pipe walls. To study the effect of this material on the near wellbore area in the injection wells, core flood studies were performed that indicated no formation damage occurs, and that the material can readily clean the near wellbore. Corrosion testing was performed using kettle test protocols in synthetic brine and also with oxygen sparging. In all cases, the product was able to provide excellent cleaning capabilities and corrosion inhibition, even in the presence of oxygen.
A Unified Mathematical Model for Unconventional Reservoir Simulation
Authors: Wu Yu-Shu , Fakcharoenphol Perapon
Published: September 2011

Unconventional hydrocarbon resources from low-permeability formation, i.e., tight sands and shales, are currently received great attention because of their potential to supply the entire world with sufficient energy for the decades to come. In the past few years, as a result of industry-wide R&D effort, progresses are being made towards commercial development of gas and oil from such unconventional resources. However, studies, understandings, and effective technologies needed for development of unconventional reservoirs are far behind the industry needs.

Unconventional reservoir dynamics is characterized by highly nonlinear behavior of multiphase flow in extremely low- permeability rock, coupled by many co-existing, processes, e.g., non-Darcy flow and rock-fluid interaction within tiny pores or micro-fractures. Quantitative characterization of unconventional reservoirs has been a significant scientific challenge currently. Because of complicated flow behavior, strong interaction between fluid and rock as well as multi-scaled heterogeneity, the traditional Darcy-law-and-REV-based model may not be applicable for describing flow phenomena in unconventional reservoirs. In this paper, we will discuss a general mathematical model proposed for unconventional reservoir simulation. We will present a unified framework model to incorporate various nonlinear flow and transport processes using a multi-domain, multi-continuum concept to handle multi-scaled heterogeneity of unconventional formation. Specifically, we will use extended or modified Darcy law to include the following processes: (1) non-Darcy flow with inertial effects; (2) non-Newtonian behavior (i.e., threshold pressure gradient for flow to occur); (3) adsorption and other reaction effect; and (4) rock deformation. The proposed modeling methodology has been implemented into a general reservoir simulator and will be demonstrated for its application in analyzing well tests in fractured vuggy reservoirs, non-Darcy flow, and non-Newtonian flow in porous and fractured reservoirs.
Integrated Asset Model in Camisea, Peru
Authors: Downie A. , Salazar A. , Monsalve M. , Cruells J. , Pomeraniec M. , Navarrete C.
Published: September 2011

An Integrated Asset Model (IAM) Project was carried out for the 56 & 88 Blocks of Camisea area. This area is located in the South Ucayali Basin, Peru, within the Sub-Andean fold and thrust belt. Camisea involves three anticlines with three independent world class reservoirs and is one of the most important natural gas and condensate reserves ever discovered in Latin America.

The targets of this study were to evaluate: the Field Development Plan, the Scenario Analysis, Conceptual Compression Plan, Monitoring and Surveillance plan.

The IAM was used to evaluate the potential development scenarios, and also to optimize production taking into account reservoir performance, surface facility and process plant constraints. The IAM also makes it easier for production and asset managers to diagnose potential problems at an early stage, and thus intervene before production is compromised, and provides an invaluable framework for performance analysis and decision making.

Camisea lies within an environmentally sensitive area, which has dictated an offshore-on-land strategy to minimize the number and footprint of the drilling facilities, and also places significant restrictions on the design of compression equipment which will be required to maintain production rates in the future.

The IAM was built incorporating the following models and software: a compositional reservoir model, nodal analysis, surface network modelling and process simulation. The individual models were linked together within integration software which enables dynamic linking and controlling of the various packages.

The IAM was validated against historical production data and also benchmarked against stand-alone reservoir model predictions. Several development scenarios were then investigated, including: facility debottlenecking, conversion of redundant cycling injector wells to production, compression optimization, and reservoir uncertainty. The IAM was also used to facilitate the economic evaluation of each case.
Incorporating 4D Seismic Attributes Into History Matching Process Through An Inversion Scheme
Authors: Davolio A. , Maschio C. , Schiozer D. J.
Published: September 2011

Time-Lapse seismic attributes has been showed as a promising tool to be used in the history matching process. The most common seismic attribute used to integrate these data is P-impedance. The procedure usually made is a minimization of the differences between the seismic P-impedance and the synthetic P-impedance computed from the flow simulation data through a forward modeling. On this paper, we propose a methodology that goes in the opposite way. We invert the seismic data to pressure and saturation and then incorporate these results in the history match procedure in order to integrate the inversion process with the flow simulator, using the results of the reservoir simulation to guide the process. Another feature is that instead of using only the P-impedance in our inversion procedure we are also taking into account a second seismic attribute the S-impedance, which is more sensitive to pressure than saturation variations. A discussion is presented regarding the results obtained using a model with characteristics similar to the Brazilian offshore fields and synthetic seismic data. The main contribution of this work is the integration of the seismic attributes inversion and reservoir simulation processes. We also show the advantages of the inversion procedure to obtain pressure and saturation considering prediction of petroleum production and the details used in the methodology to avoid multiple combinations of saturation and pressure in the inversion process.
Gas-Condensate Relative Permeability Curves Determined from Separator Test Data: Britannia Field Case Study
Authors: Göktas B. , Thrasher T. S.
Published: September 2011

This paper presents a methodology for determination of gas-oil relative permeability curves using well performance data from retrograde condensate wells. Computations are based on PVT, producing gas-oil ratio, flowing bottom-hole pressure and material balance. The methodology presented was successfully applied to Britannia wells across the field, and findings were verified with numerical simulation to show proper modeling of condensate banking.

Production performance of Britannia wells is monitored through back-pressure curves, constructed by plotting single-phase pseudo-pressure difference versus flow rate on log-log scale, using individual well separator test data. As condensate accumulates near the wellbore, reducing productivity, well performance deteriorates (points move left) from the established pseudo steady state (pss) deliverability line. Once productivity deterioration becomes negligible, the well performance response shows a linear trend. The empirical deliverability equation, delta pseudo-pressure versus flow rate log-log, yields a linear relationship with a slope of (1/n). Using this relationship, n is determined from the observed well deliverability line, shifted left due to condensate blockage. The coefficient C is then calculated at the pss deliverability line by assuming that the coefficient n remained unchanged.

With accurate gas-oil relative permeability data included in the two-phase pseudo-pressure integral, plotting delta two-phase pseudo-pressure versus flow rate for separator test points should develop an alignment with the pss deliverability line. An objective function is defined as the difference between the delta pseudo-pressure, determined using the empirical deliverability equation, and the measured delta two-phase pseudo-pressure for separator test flow rates. The process outlined in this paper aims to find a gas-oil relative permeability curve that produces the best alignment, that is, the minimum objective function.

In complex fields, e.g. Britannia, multiple gas-oil relative permeability curves might be needed to model condensate banking. In the absence of relative permeability data, the presented approach could provide valuable information on relative permeabilities.
Grid-Based Inversion Methods for Spatial Feature Identification and Parameter Estimation from Pressure Transient Tests
Authors: Morton K. L. , Booth R. J. , Kuchuk F. J. , Onur M.
Published: September 2011

We present and compare three different grid-based inversion methods for estimation of formation parameters and spatial geological feature identification based on pressure transient test (PTT) data from multiple-well locations. The first and second methods employ efficient adjoint schemes to determine the gradient of the objective functions resulting in the most likely set of reservoir parameters and an ensemble of updated realizations of the parameters, respectively. The second method is based on the Langevin equation. The third method uses ensemble Kalman filtering (EnKF) for data assimilation, in which the outcome is an ensemble of updated parameter realizations. These three methods use a grid-independent prior model (in view of the limited prior knowledge of the system expected to be available), described by as few parameters as possible, and consider a non-uniform grid with the highest resolution near the wells. With these methods, the existence of and location of many sub- seismic features such as strong spatial permeability variations, faults, fractures and pinch outs may be determined using exploration and production data. Such features may not be known a priori, particularly in the exploration of heterogeneous carbonate reservoirs.

We examine each method considering the degree of prior information required, the computational overhead and the applicability to the reservoir characterization workflow. Our results indicate that the first method provides a good history match to the observed PTT data and is suited for the early exploration phase of the reservoir. However, the parameters must be convolved with the smaller scale data to produce multiple realizations away from the implausibly smooth most-likely solution. The observed PTT data lies within the ensemble of predicted pressures in the EnKF and Langevin-based methods which are both applicable to probabilistic workflows where uncertainty is treated rigorously. However, EnKF seems to be computationally more efficient than the Langevin approach.
Quantitative Integration of Time-Lapse Seismic Derived Information in a History Matching Procedure
Authors: Souza R. M. , Munerato F. P. , Schiozer D. J.
Published: September 2011

The use of production data to increase the reliability of production forecasts of a field is limited, especially in early development, when there are fewer observed data and then a significant uncertainties raise. An alternative to improve the quality of the model is the use of saturation and pressure maps obtained from time-lapse seismic. The incorporation of this information has not been explored in reservoir engineering studies and has great potential for reducing uncertainties caused by lack of information and complexity of oil fields. Recent work indicates that the best way to use this information to calibrate reservoir numerical models is to convert it into saturation and pressure. Thus, this study aims to derive, from time-lapse seismic attributes, distributions of saturation and pressure in oil reservoirs.

This paper presents a methodology to estimate saturation and pressure maps simultaneously through an inversion process constrained by engineering data. These maps information are then combined with production data in a global objective function aiming at improving an integrated history matching procedure. This methodology is applied in a modified model of the "Namorado Field" (Campos Basin, Brazil), that has geological faults and high permeability channels. It was also necessary to apply an empirical modeling of the rock bulk modules regarding pressure variations, which improved the reservoir acoustic sensitivity and allowed, together with the engineering data constraints, to derive these maps. It was possible to identify the main structures that can influence fluid flow trends in the reservoir and significantly reduce time consuming and increase the reservoir behavior predictions reliability.

As major contributions of this study are the development of a methodology able to provide saturation and pressure trends regarding time-lapse information and engineering data constraints to the overall process and its quantitative application in an integrated history matching procedure.
Merging Coiled Tubing and Swellable Packer Technologies
Authors: Brooks Robert T.
Published: September 2011

For a number of years one of the main areas being developed has been multilateral wells to better access the reservoir. One of the greatest challenges in operating an efficient multilateral well is having control of where any water production is coming from. Effectively managing produced water can bring obvious benefits to the economics of a well. One tool that has not been fully exploited for this type of application is swellable packers. Coiled Tubing and Swellable Packer technologies were recently combined on a land-based operation in Holland to successfully isolate a water-producing leg of a well lateral. The operator asked for a proposed completion solution after a previous attempt to isolate the lateral had proved unsuccessful.

The proposed solution was designed to straddle the lateral entry/exit with a scab liner, isolated and anchored at either end by water-swellable packers. The straddle was required to seal inside the main bore casing and withstand a differential pressure at well operating temperatures. Swellable packers were selected from the various proven openhole isolation devices available to the industry to provide the zonal isolation required in the multi-zone intervals. This was the first swellable straddle completion in Holland in a watered out, commingled gas environment in which isolation would be contained solely by swellable packers.

The water producing lateral was successfully straddled using two water swellable packers run with base pipe between the two packers. In this application the Swellable Straddle was deployed in conjunction with an additional mechanical packer to anchor the straddle whilst the swelling process in the aqueous environment took place. A subsequent intervention with coiled tubing and a resettable Inflatable Test Packer confirmed the straddle had successfully sealed and had isolated the water producing lateral.

This paper presents a solution to the challenges of isolating laterals using swellable packers and coiled tubing, and how to verify that the junction has been successfully isolated.
Wettability Alteration at Optimum Fluorinated Polymer Concentration for Improvement in Gas Mobility
Authors: Fernandez R. , Fahes M. , Zoghbi B. , El Cheikh Ali N.
Published: September 2011

In gas condensate reservoirs, deliverability starts to decrease when retrograde condensation occurs. As the bottom-hole pressure drops below the dew-point, gas condensate and water build-up impede flow of gas to the wellbore. In order to stop the reduction in productivity, many publications suggest wettability alteration to gas-wetting as a permanent solution to the problem. Previous simulation work suggests an "optimum wetting state" to exist where maximum gas condensate well productivity is reached. This work has direct application in gas-condensate reservoirs, especially in identifying the most effective stimulation treatment which can be designed to provide the optimum wetting conditions in the near-wellbore region.

In this work, we aim to show the existence of such an optimum state of wettability that result in maximum gas mobility and in an increase of the relative permeability curves. We present an experimental study on Berea sandstone rocks treated with a fluorinated polymer and investigate the optimum fluorinated polymer concentration that would alter the wettability to intermediate gas-wet. Different experimental techniquesincluding flow tests and spontaneous imbibition are conducted to examine the effect of treatments on wettability. Interaction between rocks and the fluids is studied using a MicroCT scanner.

The studies in this area are important to improve the productivity of gas condensate reservoirs where liquid accumulates, decreasing production of the well. Efficiency in the extraction of natural gas is important for the economic and environmental considerations of the oil and gas industry. Wettability alteration is one of the newest stimulation methods proposed by researchers, and shows great potential for future field applications and further research studies.
Incorporation of 4D Seismic in the Re-Construction and History Matching of Marlim Sul Deep Water Field Flow Simulation Model
Authors: de Brito Daniel Ullmann , Caletti Luciano , de Moraes Rafael Jesus
Published: September 2011

Seismic data incorporation in reservoir simulation models history matching (HM) studies has been continuously growing. 4D seismic data, in contrast with well production data, can provide a very good scenario of fluids arrangement along reservoir. In this work we describe how 3D and 4D seismic data gathered in acquisitions performed in Campos Basin was incorporated in Marlim Sul deep water field geological model reconstruction and in assisted HM (AHM).

It is taken advantage of both 3D and 4D seismic data in several stages of the study, for instance, in the construction of a new porosity – most influential in impedance – model by using a methodology based on the inversion of synthetic seismic (calculated by petro-elastic model) in porosity through an optimization process that aims to reduce the difference between observed and synthetic impedance, and when defining influential parameters based on fluids displacement registered by seismic signal, by using a technique based on the creation of transmissibility multipliers parameters regions that considers the fluids displacement shown in 4D signal. Another relevant point is the use of information from reservoir and 3D seismic data when weighting the 4D data in the objective function.

Combining the above mentioned techniques with the knowledge of the field – supported by the 3D seismic data – which allowed, for instance, identification of faults – where fault transmissibility multipliers were used as parameters in the HM process – a fairly good agreement on the observed well and seismic production data was achieved.

HM studies using AHM tools have been shown a much more time-efficient technique when compared to manual HM. The incorporation of 4D seismic data can considerably improve the HM quality by improving the reservoir description, once it increases the ability of describing fluids arrangement and pressure distribution. The techniques successfully applied in the Marlim Sul field HM support these conclusions.
Effective Well Placement and Trajectory Planning Approach through Collaboration Environment Tools
Authors: Al-Baqawi Ahmed M. , Al-Naim Hamad A. , Araque Arcides J. , Habbtar Ali H. , Ismail Menhal A. , Al-Kanan Adnan A. , Al-Utaibi Abdullah A.
Published: September 2011

Well placement and trajectory planning is a critical and challenging task in any Oil & gas field development plan. This has always been a task that requires a strong team effort to ensure the best predictions and estimations are performed to penetrate the desired reservoir development zones and achieve the expected production rates. Numerous iterations with a high level of interaction between Reservoir Management, Reservoir Simulation, Reservoir characterization, Geology and Geophysics are expected when planning a new well or a difficult sidetrack.

Each member of the well planning team has his/her own environment along with dedicated standalone software tools. Today, with the introduction of the Intelligent Field center to provide the collaboration environment for the involved expertise along with the proper tool to offer a strong integration of different data sources in a single software environment that allows a team of field geologist, geophysicist, reservoir and simulation engineers to evaluate the best prospects available in planning any new drilling opportunity, furthermore the team is able to choose the best well azimuth and inclination based on reservoir properties and performance.

This paper discusses a newly integrated well planning process utilizing a collaboration environment to review seismic, well log cross sections, historical production and simulation predictions enabling the well planning team to place their gas wells using a reservoir 3D viewer, incorporating the reservoir simulation model, and run various cases and sensitivities. In This paper, full examples illustrate how effective software integration can optimize the time required to plan a new well without overlooking any important aspect. In addition, the paper discusses the lessons learned from this experience and how this approach changes the mechanism of an integrated well planning team working together.
Construction Project for the First Dendritic Well Offshore in Brazil
Authors: Guimaraes Zacarias , Duque Luis , Almeida Victor , Barros Robledo , Teles Carlos A. , Paixao Luiz , Pedroso Carlos
Published: September 2011

The application of the recent technique of creating lateral tunnels by acid jetting into the formation has been a topic of discussion in Petrobras because it is a reliable, fast an economic way to increase the well productivity index in complex geology carbonate reservoirs.

In order to evaluate this technology, a pioneer intervention was carried out in the Garoupa field on a typical offshore well in Brazil. The objective was to simultaneously increase oil production and decrease water cut, by creating lateral tunnels at specific points in the well open hole section. The number of tunnels created as well as their positions were defined as a function of both, oil and water saturation profiles. Also mineralogical and geomechanical analysis were conducted as well as rock dissolution on different hydrochloric acid concentrations, in order to determine tunnel perforation rate and hole stability,

The application of this technology has generated important incomes to the oil operator and the same technique could be also applied on other different scenarios.

This paper illustrates the process from selecting the well candidate, premilary laboratory tests, treatment designs and field operation to after treatment well production results.
Enhancing Gas-Reservoir Characterization by Integrating a Reliable Formation-Testing Permeability Method Into the Workflow
Authors: Hernandez J.. , Pacheco E.. , Proett Mark A.
Published: September 2011

Permeability is one of the most important parameters in determining the productivity index and potential reserves of a producing interval. Very few instruments, however, are available for use on discovery and appraisal wells that can make this measurement. Although cores can be used, this process always leaves some uncertainty concerning the in-situ permeability and its variation across the interval. Moreover, the results are often not available as they are needed to assist in decision making. Nuclear magnetic resonance (NMR) logging tools can provide a continuous log of permeability; however, a core study is typically needed to calibrate the log. Formation testers can determine the mobility (permeability/viscosity), but the viscosity must be estimated to determine the permeability. This paper presents methods for estimating the viscosity and then deriving permeability from the analysis of formation tester pretests.

The required viscosity estimate could be obtained by considering the properties of the mud system used when drilling, given that pretest’s radius of investigation is limited to the invaded zone surrounding the wellbore. The fluid occupying the pore space in this region must be considered as mud filtrate, especially in permeable zones that are of greatest potential.

After obtaining the viscosity estimate and expressing the results of the formation pretest analysis in terms of permeability, we are able to validate them by comparing them with the actual core data. We can also use them to quantify the total reservoir flow capacity (kh) by calibrating the NMR permeability log or by up-scaling the results obtained at several depth points across the zone. Total reservoir-flow capacity (kh) can then be used to accurately forecast production capacity. In addition, this result could already compare or be validated with the total kh result obtained from a long extended drill-stem test (DST) or production test in each zone if they are performed.

In this paper, we address the steps involved in this process; field examples are included to validate all of these approaches. The primary goal of this study is to increase the use and confidence of the formation tester’s results.
The Benefits and Application of Semi-Permeable Membrane Surface Gas Detection during Managed Pressure Drilling
Authors: Tonner D.. , Al-Maslout K.. , Pinna G.. , Forber D.. , Davies W.. , Chopty J , Jaipersad M..
Published: September 2011

Advances in drilling technology in response to a need for greater evaluation and exploitation of previously marginal resources are leading to increased usage of Controlled and Managed Pressure Drilling systems. Their application on High Pressure High Temperature wells is also increasing in relation to accurate flow and kick detection provision as well as pressure management. The benefits they bring in terms of hazard mitigation, reduced formation damage and improved drilling dynamics are allowing fields with tight operating windows to be drilled with greater safety margins and better economics. A consequence of using closed and pressured systems has been the impact and use of surface evaluation techniques, particularly surface gas logging.

Despite provision of real-time information relating to reservoir pressure, fracture gradient and fluid invasion as well as high resolution flow and fluid density variation, until recently there has still been a lack of meaningful surface gas information. This was due to the fact that all surface gas detection systems except for GC tracer currently rely on atmospheric conditions to extract gas from mud in air.

By utilising a semi-permeable membrane gas extraction process directly behind the choke manifold, prior to the Mud Gas Separator, the sampling point forms part of the enclosed system. This provides significant benefits in removing any potential surface gas loss. The application and deployment of such a technique is described in this paper. The responsive nature of membrane extraction, along with the repeatability and quantitative nature of the process, lends itself well to comparison with high resolution pressure and flow data generated by the Managed Pressure Drilling system and has the potential to be used to increase drilling efficiencies. The relationship between fluid composition and gas in mud volumes at surface, with derived reservoir pressure and surface parameters is examined in this paper.
Effect of Reservoir Fluid Type on the Stimulation of Carbonate Cores Using Chelating Agents
Authors: Mahmoud M. A. , Nasr-El-Din H. A. , De Wolf C. A. , Alex A. K.
Published: September 2011

Different fluids have been introduced in the oil industry to be used as alternatives to HCl. Chelating agents such as EDTA (ethylenediaminetetraaceticacid), HEDTA (hydroxyethylenediaminetriaceticacid), and GLDA (L-glutamic acid-N, N-diacetic acid) have been introduced to be used as stand-alone stimulation fluids. These fluids can be used to stimulate water injectors, oil, or gas producers, therefore, the effect of the type of reservoir fluid on the stimulation process should be investigated.

In this study, 0.6M concentration of GLDA, EDTA, and HEDTA were used in the coreflood experiments on carbonate rocks at 300°F. The cores were saturated with water, oil, or gas to determine the effect of reservoir fluid type on the performance of the chelating agents with the carbonate cores. The different chelants were injected into the calcite cores saturated by oil and gas after flooding the water into the cores until the residual saturations were reached. The effect of using 10 vol% mutual solvent (ethyleneglycol-monobutyl-ether) in the preflush on the stimulation process was examined. CT was used to scan the cores after the treatments, and the 2D images were used to characterize the wormhole and face dissolution.

GLDA at pH of 4 stimulated calcite cores better than HEDTA at 300°F at different injection rates. No face dissolution was observed at low injection rate and high temperature in the case of GLDA. The results obtained with carbonate cores saturated with nitrogen gas were almost similar to those obtained when the cores saturated with water. Using mutual solvent as a preflush in the oil-saturated cores removed most of the oil from the core and water-wet the calcite allowing reaction of chelants with calcite, similar to the case of water-saturated cores.
Incorporating 3-D Seismic, Well and Production Data into Reservoir Models Using Co-Simulation
Authors: Le Ravalec-Dupin M. , Da Veiga S. , Tillier Elodie
Published: September 2011

A reservoir model is a grid with petrophysical properties such as porosity and permeability assigned to every grid blocks. Many surveys evidenced correlations between acoustic impedance and porosity or between porosity and permeability. Therefore, acoustic impedance can help to interpolate porosity and permeability in the inter-well region. This can rely on simple linear relationships or co-simulation, which allows for jointly simulating several correlated variables with distinct means and covariances.

First, we develop a co-simulation algorithm to generate reservoir models honoring 3D seismic and well data. It makes it possible to simulate realizations for petrophysical properties, which respect well data and the trend given by seismic. The dependence between the target petrophysical property and seismic is driven by a linear correlation coefficient. A change in this coefficient results in a change in the co-simulated realization. Such a feature is of interest for adjusting realizations to dynamic data like production or 4D-seismic data. Therefore, the geological co-simulation step is incorporated into a standard workflow involving both upscaling and flow simulation to eventually estimate numerical production responses. These ones are then compared to the actual production data. If the production data match is too poor, linear correlation coefficients are adjusted and the whole workflow is repeated. The matching process ends up with models respecting the available seismic and production data.

We investigate two perturbation schemes. The first one involves variations in the correlation coefficients between acoustic impedance and porosity and between porosity and permeability. The second one focuses on a particular use of co-simulation: the joint simulation of two correlated variables with identical means and covariances. This process can be applied for instance to simulate porosity. Hence, variations in the correlation coefficient induce variations in the spatial distribution of porosity heterogeneities. Both perturbation schemes are complementary. Therefore, co-simulation can be envisioned as a perturbation technique to drive history-matching processes. A few numerical experiments are then presented to show the applicability of the proposed matching methodology.
Using a Friction Pressure Reducer To Extend the Operational Pumping Window in Horizontal Open Hole Gravel Packing
Authors: Jardim Neto A. T. , Prata F. G. , Silva C. M. , Barros A. C. , Souza L. A. , Rocha T. G.
Published: September 2011

The Horizontal Open Hole Gravel Pack (HOHGP) is the preferred completion method employed in Campos and Espirito Santo basins, offshore Brazil. To pack the well, the proppant is pumped such that the alpha wave is propagated from the heel to the toe of the well and the beta wave then propagates from the toe to the heel. During the alpha and beta waves, the carrier fluid is diverted into and must travel through the narrow annulus between the screen base-pipe and wash-pipe to the toe, where the perforated base pipe is located. This diversion raises the friction pressure significantly. When pumping the beta wave, the friction rises even more because the fluid must travel through the gravel placed during the alpha wave before it can flow through the screen.

The surface pressure required to overcome this high friction pressure can reach or exceed the formation fracture pressure, resulting in early termination of the gravel pack placement due to severe fluid leakoff to the formation. Some solutions are available, but the preferred method of dealing with pressure increases when performing HOHGP offshore Brazil is the ultra-lightweight (ULW) proppants and BOP open (return through the flow line). However, in some cases when the extended horizontal section is associated with a low fracture gradient and washed out zones, the pumping window expansion provided by ULW proppants and BOP open can be still not enough to perform the job comfortably. In such scenario a friction pressure reducer (FPR) was introduced to avoid pressure increases while pumping the gravel pack. The FPR can also minimize friction pressure increases in wells packed using intermediate-density ceramic gravels.

This paper describes 3 successful case histories of circulation tests and HOHGP performed with FPR added to the completion fluid. The focuses are the challenges faced, lessons learned and advantages of using the FPR to extend the safe pumping window.
Real-Time Wellbore Friction Analysis to Detect Onset of Drillstring Sticking during Extended Reach Well Drilling: Case Study
Authors: Fazaelizadeh M.. , Hareland G.. , Wu Z.. , Tahmeen M..
Published: September 2011

Wellbore friction modeling is considered as an important assessment to aid real-time drilling analysis and predict drilling troubles such as tight holes, poor hole cleaning, onset of pipe sticking etc. The torque and drag are typically the limiting factors facing the drilling industry to go beyond a certain measured depth in extended reach drilling. In extended reach drilling, surface measurement of weight on the bit and torque differ from downhole measurement due to the friction between the drill string and the wellbore. This friction force can be used to estimate an overall friction coefficient. The overall friction coefficient value versus measured depth while drilling can be used as an indicator during different drilling operations.

In this paper, for wellbore friction analysis, a newly-developed analytical model was used to estimate the friction coefficient versus measured depth. A field case is drawn from a deviated well drilled in western Canada where the drillstring got stuck during drilling operations. The time-based field data were analyzed in detail to find onset of drill string sticking from the recorded data while tripping drillstring in. Also, the study provided an opportunity to examine the validity of the new wellbore friction model using a field case.
Ni-Fe Nanoparticle: An Innovative Approach for Recovery of Hydrates
Authors: Bhatia K.. , Chacko L..
Published: September 2011

Gas hydrate is a crystalline solid consisting of gas molecules, each surrounded by a cage of water molecules. They produce 160 times their volume of methane which is an infinite source of energy waiting to be tapped, but the technology to recover these hydrates is at its infancy. Recovery of gas from hydrates requires the dissociation of gas hydrates which can be accomplished in at least three ways: thermal recovery, depressurization or by chemical inhibition. But, the problems associated are: Most chemical additives (salt, methanol, and glycol) cause pipe and equipment corrosion, ecological problems.Preheated gas or liquid transportation down to hydrate zone is accompanied by extensive heat loss.Microwave or electromagnetic method also requires vast energy transfer to decomposition zone and is inefficient.

This paper proposes the injection of air-suspended self heating Ni-Fe nanoparticles (50 nm) in the hydrate formation through horizontal well. These particles will penetrate deep into the class I, II and H hydrate reservoir by passing through the cavities (86–95 nm).

The self heating of particles in a magnetic field is caused by hysteresis loss and relaxation losses. These particles cause temperature rise up to 42°C in formation leading to disturbance in thermodynamic equilibrium and causing the water cage to decompose and release methane. In this technique, the pressure of the fluids in contact with hydrate is lowered, pushing the hydrate out of its stability region and leading to its decomposition.

It has been discovered that the less expensive, readily available Eggwhite (Ovalbumin) can catalyze the reaction which results in large scale formation of these nanoparticles. The main advantage of this technique is the very low dosage requirements (small quantity required for 1m3 of Hydrate decomposition). Moreover, the nanoparticles used are non-poisonous, environment friendly.
Retention of CO2-Foaming Agent in CO2-Foam Flooding of Heterogeneous Carbonate Reservoirs
Authors: Fjelde Ingebret , Zuta John , Berenblyum Roman
Published: September 2011

The efficiency of carbon dioxide (CO2)-flooding in highly heterogeneous reservoirs may be low due to poor macroscopic sweep. One of the possible ways to increase macroscopic sweep efficiency is by reducing the CO2 mobility by foam. Retention of the foaming agent during CO2-foam flooding is an important aspect affecting both technical and economical potential of the process.

This paper presents both experimental and numerical simulation studies performed to investigate the retention of CO2-foaming agents in heterogeneous carbonate reservoirs. These reservoir types consist of high permeable "thief zones" - fractures or high permeable layers and the rest of the reservoir - matrix or low permeable layers. The retention of CO2-foaming agent was studied in flow-through laboratory experiments with CO2-foaming agents; branched ethoxylated sulphonates with different ethoxylation degree in outcrop Liege chalk rock at 55°C. The retention of the foaming agents was determined by breakthrough curves based on chromatographic separation between the foaming agent and a tracer. The flow-through retention experiments were reproduced in a numerical simulator.

The results indicate that the retention (the amount of foaming agent lost per rock weight) depends on the type of foaming agent and oil saturation. It is concluded based on simulation results that the amount of the foaming agents retained in heterogeneous reservoirs would strongly depend on its transfer mechanism from high into low permeable zones. The diffusion process is slow and therefore the foaming agent might penetrate only into a certain fraction of the matrix blocks or low permeability layers during the project life time. The retention of the foaming agent in these heterogeneous carbonate reservoirs may therefore be much lower than estimated based on viscous floods.

A numerical model describing diffusion and retention by adsorption was established. A good match between experimental and modeling results was obtained without individually tuning the numerical model for each specific experiment. Additional simulation results showed that on the field scale the amount of foaming agent retained in heterogeneous reservoirs will depend on the number of high permeable zones and the size of the matrix blocks.
Novel Drilling Technology Delivers a Step Change in Challenging Deepwater Operations
Authors: Clausen J.. , Rebellon J.. , Blanc J.. , Barton S..
Published: September 2011

Jar technology has been around in the oil industry for several decades and its basic principles have remained primarily the same. As the oil industry moves forward in the exploration and development of unconventional hydrocarbon reserves, the demand for tougher, more reliable, and safer tools is more critical. Deeper wells and more complex well geometries are pushing the drilling envelopes, requiring tools to be engineered not only to withstand higher stresses downhole, but also to provide higher levels of safety on the rig floor. Through the engineering of simple but ingenious features, this paper describes how jar technology has been taken to a higher level.

A jar has been designed acknowledging the most important features required in the current demanding drilling scenarios. The industry is not only looking for safer and more reliable tools, but also tools that will provide higher firing loads to increase the levels of success of freeing a drill string during a stuck pipe incident. The loads delivered during the first hours of a stuck pipe event can significantly improve the chances of retrieving the drill string safely to surface.

The design features employed in this new technology maintain the same operating procedures of standard designs, but have increased the torque, tensile, and pressure ratings of the tool. In addition, current technology can suffer damage from excessive internal pressure build up when the over-pull rating of the tools are exceeded; particularly in deepwater applications where heave can be a contributing factor. A device has been engineered to protect the tool if such a condition is reached. The new jar also features a modular safety mechanism that will eradicate the use of the traditional safety collars eliminating the potential hazards of dropping objects on the rig floor.

This paper will provide an overview of the innovative technology, plus review the initial field trials. Testing and field trials will demonstrate how this technology is a true step change, matching the growing demands of the drilling industry.
Success Story: Squeeze Cemented 9 Interval Perforations in One Shoot!
Authors: Winarga Kanuga , Gholib Ramadanus , Wahono Teguh , Dewanto Christianto Widi
Published: September 2011

Historically, squeezing cement into 9 Interval Perforations in one procedure is almost never happen in actual operation but in August 2010 we did it in Mengkapan Field and finish with success.

Previously in the Melibur oil field in Sumatra, Indonesia, three or four cement-squeeze jobs have been required before the zone holds pressure. Failure was thought to be due to gaps remaining after the squeeze-cementing job between the oil-wet matrix rock and the water-based cement.

This paper will tell a success story in Mengkapan Field by squeeze out 9 interval perforations (850 ft height) in one shot with a surfactant soak that was used to increase the squeeze-cementing success rate. The function of the surfactant was to mobilize trapped oil by creating an emulsion, and to change the oil-wet rock to water-wet rock. The surfactant was injected into the rock formation and allowed to soak for 24 hours. Then the squeeze-cementing job was performed as usual. This surfactant soak was trialed in three wells, and they passed the pressure-holding test after an average of two squeeze-cement jobs.

It was concluded that surfactant treatment is a great solution to increase squeeze cementing quality, and is now standard practice in this field.