bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

AbstractPermeability 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.
A New Al-Based Stabilizer for High pH Applications
Authors: El-Monier I. A. , Nasr-El-Din H. A. 
Published: September 2011

Abstract
Sandstone formations are exposed to a variety of high pH fluids, including: hydraulic fracturing using high pH borate gels, alkaline-based chemical EOR methods, water-based drilling fluids and cementing filtrate. High pH values can trigger fines migration, and subsequent loss of permeability and well productivity. An Al/Zr-based clay stabilizer was developed to control fines migration at high pH applications. The objective of this study is to assess the effectiveness of this new stabilizer and compare its performance with commercially available stabilizers.
Laboratory studies were performed using Berea sandstone (8 wt% clays; mainly kaolinite) cores (6 in. length and 1.5 in. diameter). Tetramethyl ammonium chloride (TMAC) and choline chloride were used for comparison as two commercial clay stabilizers. Various coreflood experiments were conducted to determine the effect of the three stabilizers on core permeability (from 64 – 100 md) at various temperatures up to 300°F. In these experiments, a preflush that included 2 wt% stabilizer was injected and was followed by injection of 2 wt% NaOH solution. The later represented high pH filtrate that can invade the formation during any treatment that includes alkaline fluids. The pressure drop across the core was measured and samples of the core effluent were collected. Inductive Coupled plasma was used to measure the concentrations of Al, Zr, Fe, Ca, and Mg.
Lab results indicated that the new clay stabilizer worked effectively up to 300°F. No reduction in permeability was noted in any of coreflood tests using sandstone cores of various mineralogies and initial permeabilities. The concentrations of various cations were found to be a function of core mineralogy. TMAC and choline chloride was not effective when followed by fresh water and incompatible with the high pH fluids. The new stabilizer is environmentally friendly, and can be used in hydraulic fracturing, and alkaline-based chemical EOR methods to mitigate clay related problems.