bluuebunny/crossref_metadata_2025_split huggingface dataset:
Real-Time Casing Design Optimization: A Case Study in Using Managed Pressure Drilling to Develop an Adaptive Well Design and Eliminate Casing Strings on a Deep Water Exploration Well
Authors: Sugden Catherine , Bacon William , Gabaldon Oscar , Borges José Umberto , Soares Cristiane Maravilha , Falcão José Luiz , Nogueira Emmanuel Franco , Vanni Guilherme Siqueira , Chita Luiz Carlos 
Published: June 2014

Abstract
A Petrobras deep water exploration well is planned to be drilled in over 2438 m (8000 ft) of water offshore Brazil. As is typical of deep water wells, it has a narrow drilling window between pore pressure and fracture gradient requiring many casing strings to reach TD. Because pressure related problems are often extremely costly when drilling conventionally in deep water, initial design assumptions were conservative, assuming the maximum pore pressure and minimum fracture gradient for casing point and pipe selection. As with all conventional casing designs, the resulting pipe has limited capacity to withstand increased burst and collapse loads associated with extending hole sections if the opportunity arises.
Managed Pressure Drilling (MPD) enables the development of an adaptive well design by providing three key advantages over conventional drilling; 1) The ability to detect kicks and losses extremely accurately (in gallons, rather than barrels); 2) The ability to rapidly respond to and dynamically control detected kicks and losses by adjusting backpressure on the annulus, keeping their volumes small; and 3) The ability to perform dynamic pore pressure and formation integrity tests. Detecting and responding to kicks rapidly allows for the well to be designed with smaller kick tolerances. Furthermore, by keeping the kicks small they can be circulated out quickly without requiring conventional time consuming well control operations which often lead to further hole problems. When this advantage is coupled with dynamic pore pressure and dynamic formation integrity tests, real time optimization of casing points can be achieved safely with reduced risk of costly well control incidents.
The method presented here, applicable to any deep water well, uses low, expected and high pore pressure / fracture gradient estimates to develop an adaptive casing design for the well. In this paper, kick tolerance calculations for selecting casing points using MPD are defined. The effect of reduced kick tolerance requirements due to the application of MPD is demonstrated and finally, an adaptive procedure for real time design optimization of the well is presented. The method results in decision criteria that identify key depths where casing strings can be eliminated without compromising the ability to reach objective TD. The resulting adaptive casing design will most likely eliminate at least one and has the potential to eliminate two casing strings, representing significant cost savings.
New Gyro Drilling Technology Delivers Accurate Azimuth and Real Time Quality Control for All Well Trajectories
Authors: Weston John , Ledroz Adrian , Ekseth Roger 
Published: June 2014

Abstract
In response to the increasing demand for a reduction in the uncertainty of wellbore placement to minimise drilling risks and potential liabilities, a new gyro survey tool capable of operating at any attitude during the drilling process has been developed; an all attitude gyro while drilling tool.
Gyro survey systems determine the direction of the survey tool in the wellbore, the tool azimuth, using measurements of the horizontal components of Earth's rotation in a process known as gyro compassing or north finding. Current gyro while drilling systems are based on angular rate measurements taken about two axes only. These measurement axes are both perpendicular to the direction of the wellbore and perpendicular to each. While two-axis systems provide accurate estimates of azimuth near vertical, this accuracy degrades as inclination increases, with the azimuth becoming indeterminate due to a mathematical singularity at 90 degrees inclination. To overcome this, an additional rate measurement about the along-hole axis of the tool needs to be performed. Only gyro instruments with 3 orthogonal sensitive axes, as adopted in the new tool, are capable of measuring the full horizontal Earth rate signal in all wellbore geometries.
This paper describes a number of innovative technological advances that have allowed all attitude gyro while drilling to become a reality, including:
a brand new gyroscope designed specifically for the down hole drilling environment a new system mechanisation to control gyro biases a signal processing technique known as Continuous Adaptive Processing that estimates the g-sensitive bias errors at each gyrocompass station a more robust quality control scheme
The new high angle gyro while drilling system is well suited to handle any wellbore placement needs. These include high inclination kick-offs, in-fill drilling, relief wells, and the provision of improved accuracy in east-west wells. With the improved reliability of the data comes increased confidence that the resulting survey is representative of the true wellbore trajectory. The detection of gross errors can also be accomplished by comparing real time gyro while drilling and MWD data. Further, with the memory multishot capability that is available, reliable high accuracy surveys from section TD to surface are generated verifying both MWD and gyro while drilling performance on the trip out eliminating the need for separate and rig time dependent gyroscopic surveys.
Finally, a number of case studies are presented to illustrate the performance capabilities of the new gyro system over a range of well trajectories and latitudes.
The all attitude gyro while drilling system not only allows the survey reliability goals to become a reality in a cost effective manner - as set out in the earlier QC papers published in conjunction with the SPE Well Positioning Technical Section - but also does this real time, while drilling.
Viscoelastic Behavior and Proppant Transport Properties of a New Associative Polymer-Based Fracturing Fluid
Authors: Gomaa A. M. , Gupta D. V. , Carman P. 
Published: June 2014

Abstract
A new thickening system extends the temperature range of traditional viscoelastic surfactant-based fluids and provides additional downhole benefits. Based on a low-molecular-weight associative polymer, the thickener forms an associative gel with surfactants at elevated temperature. This results in a gel structure that can carry proppant. Recent laboratory work has shown that viscosity alone may not accurately assess proppant transport. Thus, the aim of this paper is to evaluate rotational and oscillatory measurements to determine the viscous and elastic properties of the fluid. In addition, dynamic and static proppant settling tests were conducted using a high pressure/ high-temperature visualization cell to confirm the effect of elastic properties on proppant settling. This combination of measurements can better predict whether the fluid can be applied successfully in the field.
Thirty-three different formulae across a wide polymer and surfactant concentration range were examined at temperatures up to 250°F. Also, the effect of other fracturing fluid additives, such as friction reducers and nonemulsifying agents, were examined. Finally, proppant-settling tests were conducted with three proppant types of the same size, but different density and shape at a range of concentrations.
Experimental results show that each formula had a certain operating temperature range where the elastic modulus dominates. A polymer-to-surfactant concentration ratio of 1.4 was found to give the widest working temperature range with the highest elastic characteristics; the same range also gives better proppant suspension. At temperatures less than 100°F, the viscous regime was dominant for all tested formulas. However at the same temperature, the elastic modulus increased with shear rate. This gives a good proppant-carrying capacity during dynamic conditions (mixing and injection) with a small pressure drop. The friction-reducing agent was found to have a tendency to reduce the operating temperature range. However, the non-emulsifying agent reduced the effect of the friction reducer and enhanced the performance.
Case Study: Sand Management Evolution in a Brownfield
Authors: Gonzalez Luis Daniel , Rivero Maria Elba , Curteis Charles , Amaleswaran Devina 
Published: June 2014

Abstract
A Brown field has been in production for over 30 years. A redevelopment plan started in 2004 to revamp oil production under an Alliance partnership between an Oil & Gas Company Malaysia and Schlumberger. The mentioned Brown field is a multilayered reservoir where the UCS can vary from 1500 psi in the consolidated sand until less than 800 psi in the shallow zones.
Based on a geomechics study and existing production history of the field, unconsolidated producer sands were identified and sand control methods were evaluated according to the degree of achieving the goals, and reducing risk, the result indicates that the Cased Hole Gravel Pack with Alternate Path System was preferential. Additional information was obtained in the latest campaign during the retrieval of gravel pack screens in 2 sand producing wells, which gave a better understanding of the failure mechanism in the previous gravel pack operations.
The main changes in the design of sand control systems during 8 years includes adopting a perforating strategy of performing a mechanical backsurge, increasing shot density and charges with low debris, use of a 3-way sub tailpipe system to avoid problems associated with breaking flapper valves and debris accumulation, number of cup packers, size of screens, slurry concentration and back pressure applied during the treatment. Furthermore the evolution in the sand control management have showed benefits such as increasing the number of gravel pack zones per well, performing longer gravel packs, installing permanent downhole gauges and using bigger tubing.
This paper presents as case study of the evolution and the impact of the sand management systems, showing the significant changes in the design and execution of gravel packs and describing the reasons for those changes. The impact is analyzed on the basis of formation damage, GP factor, execution, risks and results of the initial production.
Deciphering Return Permeabilities
Authors: Li David , Leonard Russell , He Wenwu 
Published: June 2014

Abstract
Return permeability (core flooding) laboratory tests are routinely performed in conjunction with the drilling fluid selection process in order to assess the potential damage a fluid can cause to a formation.
A typical return permeability test is conducted at high-temperature, high-pressure (HTHP) conditions on either an actual formation or on replacement cores. A quantitative value of the percentage of return permeability is often used to provide insight on potential formation damage. While there have been various published articles focused on the value of the return permeability and associated damage mechanisms, there is an apparent lack of subsidiary data itself. Such subsidiary data include filtrate losses and flow initiation pressures. What do these values indicate and is there a correlation between these values with respect to return permeability?
This paper will answer these questions by examining the data from 325 return permeability tests. These return permeability tests were conducted over a wide array of permeabilities with cores ranging from less than 0.5 mD to more than 2 D, different pore structures and varying clay content. The temperature conditions ranged between 80 to 350°F and differential pressures between the wellbore and reservoir ranged from 150 to 1500 psi, which simulated a variety of wellbore conditions – including depleted wells. The objective of this study was to obtain the correlations between the rock permeabilities, fluid loss, flow initiation pressure, return permeability figures and the length of time for the return permeability to reach steady state.
Our study indicates that correlations between fluid loss filtration and return permeability are more evident in high-permeability core plugs using oil as the production fluid while correlations between flow initiation pressure and return permeability are more apparent in low-permeability core plugs using gas as the production fluid. The increase in filtration may imply that a longer length of time is required to achieve return permeability steady state. Overbalance pressures of less than or equal to 500 psi may be less damaging in comparison to overbalance pressures of more than 500 psi.
Integrated Workflow for Lost Circulation Prediction
Authors: Ghalambor Ali , Salehi Saeed , Shahri Mojtaba P. , Karimi Moji 
Published: June 2014

Abstract
Lost circulation has plagued the industry since the beginning of drilling. Historically, severity of losses has been categorized based on the amount of barrels lost to the formation, i.e., seepage, partial, and total. Though helpful, this strategy doesn't help understand the underlying drive mechanism(s) for losses and doesn't provide enough data to propose a solution. The recently adopted category is focused on the lost-circulation mechanism based on the properties of the exposed formation; these classifications are losses to 1) pore throats, 2) induced or natural fractures, and 3) vugs or caverns. This study provides an integrated workflow to predict expected losses for such classification/mechanism of losses.
Mud loss through fracturing is categorized based on fracture types, i.e., natural or induced fractures. Different models are used with respect to the fluid-loss mechanism in natural and induced fractures. These models take into account the effect of fracture breathing. In addition, mud loss through the pores on the wellbore and the fracture face is modeled based on formation and mud-cake filtration properties, coupled with the fracture losses. Losses through induced fractures generally occur when ECD exceeds fracture gradient. This happens due to erroneous prediction of the mud weight window, lack of the key information, harsh downhole pressure/temperature and some other operational factors. A field case from deep water Gulf of Mexico is presented in this paper showing how an inaccurate mud window can yield in drastic mud losses. In addition, rock properties and field in-situ stress govern fracture width and fracture propagation. Losses to vugs/caverns are usually total losses due to very large openings in the rock; recommendations are provided on how to control severe losses.
Lost circulation not only causes the adverse effect of mud loss itself; it can also lead to several other issues, such as formation damage, stuck pipe, hole collapse, and well-control incidents. The current industry trend is moving towards drilling more low-pressure zones, and lost-circulation planning is becoming a vital part of these projects.
Knowledge of the type and the expected amount of mud loss can help engineers select the most appropriate and effective solution and preplan accordingly. This information also provides criteria to evaluate the effectiveness of the applied lost-circulation strategy. In this study we review LCM treatments, wellbore strengthening, MPD, and CwD as some of the most common remedial techniques.
Insights into the Process of Effectively Acidizing Naturally Fractured Reservoirs
Authors: Salimi Siroos , Ghalambor Ali , Hayer Hossein 
Published: June 2014

Abstract
This paper presents the simulation results of acidizing process in naturally fractured reservoir (NFR) by application of advanced numerical technique. Accurately predicting fracture and matrix flow is often critical to assessing well productivity in naturally fractured reservoirs.
Fracturing with acid (usually hydrochloric acid [HCl]) is an alternative to propped fractures in acid-soluble formations such as dolomites and limestones. Computational Fluid Dynamics (CFD) is a computational technology that enables study of the dynamics of materials that flow. The CFD code is used to simulate the fluid flow through the fracture and matrix. The model is based on coupled multiphysics phenomena such as Darcy's law in porous media, reaction flow equation for the fracture and fracture growth by acid dissolution. Reaction flow in the fracture is controlled by diffusion and convection terms. The model simulates the impact of fracture geometry, acid properties, fracture width, matrix permeability on the acidizing process.
The results show that diffusion and convection terms will control the transport of acid through the fracture (as there are limits to this process). when the mass transfer coefficient (Kg) is higher than 10e-5 m2/sec, the mechansim of acid trasnport will be controlled by convection term on the fracture surface. Physically, this means that acid transport to wall by diffussion term is negligilble. When the fracture width is higher than 200 micron (0.00002 m), the acid will react with the most of the surface of the fracture and it will be dissolved by acid considerably. The mass transfer coefficient will also play an important role during acidizing process as the results show. The results of this study were used as guidelines to design a more effective acid job by predicting the acid penetration and acid volume for matrix acidizing in naturally fractured reservoirs. Furthermore, the contrasts in job design for lithology of the carbonate formation are also presented.
Development of Injectivity Damage Due to Oily Waste Water in Linear Flow
Authors: Jin Lu , Wojtanowicz Andrew K. 
Published: June 2014

AbstractNumerous laboratory experiments show that even very small amount (below 100 ppm) of oil in injected water can cause severe injectivity damage. On the other hand, field experience in produced water re-injection reveals difficulty (and high cost) of de-oiling the water with very low oil concentration. Moreover, not only the oil amount but its droplet size hampers the injection process. The most recent example of this problem is the commercial failure of downhole oil water separation (DHOWS) technique due injectivity damage resulting from incomplete separation and residual oil in the injected water.Although injectivity decline caused by oil droplets has been studied experimentally, there is still lack of an easy-to-use and widely accepted model to predict the decline behavior. In this work, we developed an analytical model to predict time-dependent advancement of the water permeability reduction in linear flow by analyzing experimental data obtained from linear core flooding.The model considers mass transfer of oil phase from the water oil mixture to the rock due capture effects by dispersion, advection and adsorption inside the rock. As the captured oil saturation increases, permeability reduces following the relative permeability drainage relationship. The reduction stabilizes when the oil saturation comes to an equilibrium value controlled by oil droplet size and injection velocity. Resulting from the model is a distributed change of permeability vs. time and distance from the point of injection that can be converted to the overall injectivity damage or skin factor. The model is calibrated using published experimental data from prolonged core floods with oil-contaminated waste water. Theoretical runs of the model demonstrate all the effects known from experimental observations, such as an ultimate value of captured oil saturation, the effect of oil droplet size and concentration, injectivity improvement at high rate, and the rock wettability effect.
Three-Dimensional Modeling of Wellbore and Perforation Stability in Weak Sands
Authors: Alquwizani S. A. , Sharma M. M. 
Published: June 2014

Abstract
A three-dimensional numerical model was developed to simulate the stability of wellbore and perforation tunnels completed in weak sandstone formations. Post-yield mechanical behavior of granular materials is incorporated in the model to study the mechanical instabilities associated with such completions. Fluid flow calculations are also incorporated in which they are computationally coupled with the mechanical calculations to generate pore pressure and stress distribution in the sand matrix. In addition, the model presented here extends the use of the sand erosion criterion developed by Kim (2010) in order to compute the mass of the produced sand.
It has been shown through field experience that sanding is influenced by several factors such as completion geometry, wellbore inclination, perforation orientation, and in-situ stress anisotropy. The developed model is capable of simulating the impact of these factors and assessing their sanding risk through advanced modeling and meshing techniques. The model can be utilized accordingly to design a wellbore completion that maximizes the mechanical stability and reduces the sand production rate. Different production and operational conditions can also be simulated to determine the onset of sand production and the critical drawdown pressure.
Results obtained from the model shows that vertical wellbores produce less sand in regions where the overburden stress is the maximum in-situ stress. In horizontal wellbores, vertically oriented perforations are more stable than horizontally oriented perforations and can withstand higher drawdown before sand is produced. A wellbore model with multiple perforations was also constructed to investigate the effect of mechanical and hydraulic interference from adjacent perforations on the evolution of plastic strain. It was shown that perforation spacing has an influence on both the magnitude the spatial spread of the plastified zone. By combining the effects of phasing angle, perforation density, and wellbore diameter, the model is capable of determining the completion configuration with the least sanding risk.
Removal of Plugged Asphaltene in a Reservoir by Earthquakes
Authors: Uetani Takaaki , Matsuoka Toshifumi , Honda Hiromi 
Published: June 2014

Abstract
This paper provides a phenomenological description of a positive correlation between earthquakes and improvement of asphaltene problems during oil production in a Japanese oil field. The studied oil field is Field ‘M’, located in the central region of Japan. Oil has been produced from this Pliocene turbidite-sandstone reservoir since 2003. Serious formation damage occurred shortly after the oil on-stream, and the damage reduced the production rates of two wells. Based on the asphaltene sludge collected at the surface production facility and other supporting facts, the damage was identified as caused by asphaltene in the reservoir.
Severe asphaltene problems similar to those observed in other cases (Leontartis and Mansoori 1987; Garcia et al. 2001; Kokal et al. 2003; Strippoli et al. 2010; Al-Qattan et al. 2012) have been reported in Field ‘M’. The oil production rates of the reservoir responded positively to certain earthquakes that frequently hit this field. Based on a phenomenological analysis of the relationships between the earthquakes and the production behaviors of the field, we concluded that the following three criteria must be simultaneously satisfied for an earthquake to influence and improve the productivity of the wells in Field ‘M’: (1) The productivity of the well is lowered, due to severe asphaltene problems in the reservoir with a flowing wellhead pressure of less than 690 kPa·abs (100 psia); the corresponding pressure loss created by asphaltene deposits in the near-well reservoir region is approximately 6,895 kPa to 10,343kPa (1,000 psi to 1,500psi). (2) The well is producing oil from the reservoir. (3) Earthquakes with a seismic intensity of not less than 3 hit the field.