bluuebunny/crossref_metadata_2025 huggingface dataset:
Influence of Casing Centralization on Cement Sheath Integrity During Thermal Cycling
Authors: De Andrade J. , Torsæter M. , Todorovic J. , Opedal N. , Stroisz A. , Vrålstad T.
Published: June 2014

The objective of primary cementing is to protect the casing and to ensure zonal isolation. It can be difficult to obtain a good cement job along the full length of a well, and casing centralization is one of the main factors that influence this. Even if the dependence of cement placement on casing centralization is well-known, little information is available on how the degree of casing centralization affects the well during its production phase. Well temperatures cycle up and down as a part of normal production operations – and well barrier materials, in particular steel, cement and rock, will consequently repeatedly expand and contract their volumes. Over time, this is likely to induce debonding and radial cracking of the cement sheath which threatens well integrity.

This paper reports the results of an experimental study mapping how, where and when the annular cement loses its sealing ability upon temperature variations, and how this is dependent on casing centralization. The studied samples consisted of rock, cement and casing, and the temperature was cycled in a controlled and programmable manner. In-situ monitoring by Acoustic Emission (AE) sensors detected the development of cracking and debonding in the samples during thermal cycling. Initial and post-experiment computed tomography (CT) scans provided complementary three-dimensional (3D) information on the geometry and location of the induced cracks and debonding.

Our study compared the thermal cycling resistance of two samples, one with centralized casing and one with a 50% casing stand-off. The AE monitoring results indicated that most of the cracking/debonding occurred during the actual heating and cooling, and not in between cycles when the temperature was held constant. The CT analyses showed that the thermal cycling caused considerable enlargement of cracks and voids initially present in the cement sheath, and this enlargement was significantly more severe when the casing was not centralized.

The paper presents, for the first time, a 3D visualization of cracks and debonded volumes in the cement sheath, and it underlines the importance of obtaining a good initial cement job. Also, it is shown that it is important to obtain a good casing centralization during well construction – not only for optimal cement placement, but also for maintaining well integrity during production.
Dual Active Heave Drilling Drawworks: From Concept to Operational Life
Authors: Fivelstad Olav , Verhoef Richard , Ogg Jeremy , Davila Sara
Published: June 2014

In 2010, a fit-for-purpose Mobile Offshore Drilling Unit (MODU) was equipped with a dual Active Heave Drilling Drawworks. As a concept, this layout was initially presented in the SPE/IADC paper 79826 "Dual Drawworks Provide Operational Redundancy and Reduce Cut and Clip Costs." After additional developments with the drilling contractor, the equipment provider and the vessel designer, this system went from concept to reality.

Fundamentally, this system is based on having two Active Heave Drilling drawworks mounted on the port and starboard side of the derrick working simultaneously as a complete 1,000 (i.s.o. 1000) ton hoisting system. The initial goals of the system were to reduce slip and cut costs, increase tripping time and provide overall redundancy for ultra-deepwater operations.

This follow-up paper will examine field performance data, provided by the drilling contractor, while looking to juxtapose the initial engineering concept with the systems capability to successfully transition dual Active Heave Drilling drawworks from concept to operational life.
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

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

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

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

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

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

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

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

Numerous 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

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

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.
The Effect of Core Dimensions on the Optimum Acid Flux in Carbonate Acidizing
Authors: Dong K. , Jin X. , Zhu D. , Hill A. D.
Published: June 2014

The results of matrix stimulation in carbonate formation strongly depend on the acid injection condition. Large amounts of lab tests indicate that an optimum acid interstitial velocity, vi-opt, exists, which results in the minimum volume of acid required for wormhole propagation (optimal breakthrough pore volume) and the most efficient stimulation. During the last decade, much progress has been made to identify the factors that affect the optimum conditions of linear coreflood experiments, including temperature, acid type, acid concentration and lithology. However, there lacks a discussion on the effect of core dimensions on the optimal conditions. Experimental results published before show strong evidence that the optimal condition changes as the dimension of core samples changes. Since the optimal condition from experimental studies is the critical information used in treatment design, it is necessary to investigate the relationship between the optimal condition and the core geometry.

In this work, a series of coreflood experiments were conducted with Indiana limestone cores at room temperature. The cores selected are relatively homogeneous to eliminate the effect of heterogeneity. The acid used is 15% plain hydrochloric acid. The core lengths range from 1-in. to 10-in. and the core diameters are 1-in., 1.5-in. and 4-in. From the experimental results, the effects of core length and core diameter are examined. The results showed that the vi-opt becomes independent of the core length when the core length reaches a value of 6 inches. These observations can help with the recommendations of the proper core length and core diameter to be used in future laboratory experiments.

The core-size dependence is important while scaling up the laboratory results to field applications. The results of this work can give a better understanding of how upscaling works. Also, with these results, the existing wormhole growth models can take into account the core-size dependence, resulting in more accurate upscaling of experimental results.
Solid Paraffin Inhibitors Pumped in Hydraulic Fractures Increase Oil Recovery in Viking Wells
Authors: Wornstaff V. , Hagen Scott , Ignacz T. , Chorney M. , Pedersen Barett
Published: June 2014

The Viking formation in southern Saskatchewan Canada represents an active area where steep production declines in the first year of production are common and are often attributed to wellbore or near-wellbore precipitation of paraffin. Excessive decline rates within the first year on production have been observed.

A producer was experiencing paraffin deposition in the wellbore and suspected it to be the reason for production declines. Conventional treatments targeted at wellbore deposition were carried out with little effect on production rates. In an effort to improve production rates horizontal treatments were attempted. These treatments resulted in brief increases in production (up to 6 weeks). Horizontal treatment success led to investigation into other treatment options. Precipitation in the formation may contribute to reduced conductivity and, therefore, lower oil production rates. Solid paraffin inhibitors delivered via hydraulic fracturing offered the best potential for success in new wells.

The chemical additive treatment was designed through product selection testing using cold finger deposition tests, compatibility testing with the hydraulic fracturing fluid system, and proppant crush prediction models. A baseline of the untreated oil characteristics was determined using offset wells. Pour point, carbon number distribution and wax percentage were analyzed in offset untreated wells and each treated well. Production trends were used to track the performance of the treatments. The solid inhibitor application effectively prevented conductivity restrictions due to paraffin precipitation issues in the proppant pack.

Placement of solid paraffin inhibitors into the Viking formation with the proppant during hydraulic fracturing increased cumulative production by approximately forty percent in the first 350 days on production and reduced decline rates. Comparing 150 untreated wells with the 90 wells treated with the solid paraffin inhibitor in 2012 has increased revenue by about 15.8 million USD over the 350-day period. Wells drilled in the same area, with similar frac treatments, depths, horizontal lengths and stages were compared.
Fines Migration in Oil and Gas Reservoirs: Quantification and Qualification Through Detailed Study
Authors: Byrne Michael , Rojas Elinor , Kandasamy Ram , Gibb Angela
Published: June 2014

Fluid flow through oil and gas reservoirs can induce movement of parts of the rock within and through the pore network. This movement or "fines migration" can have a significant impact on well and reservoir performance. Laboratory testing and detailed mineralogical study can help with quantification and qualification of the potential for and impact of fines migration. Laboratory core flood testing can be used to try to predict the potential for fines migration in any fluid phase and at any velocity. The design of the tests and the limitations of such testing need to be considered before data is too rigidly employed. Ideally, tests should be conducted with the same fluids as will be present in the reservoir, under the same temperature and pressure conditions (including consideration of depletion) and the flow rates carefully selected to replicate reservoir velocities. If tests are conducted carefully then various conclusions on the impact of fines migration on well and reservoir behaviour can be drawn. Several new cases will be presented that demonstrate the potential use of good data and the danger in badly designed tests.

Definition of the size, shape and composition of mobile fines is important in order to understand the potential impact of the fines. Quantification of potential mobile fines is useful but data must be carefully analysed. High fines content is an indication of potential fines migration damage risk but is by no means a definitive predictor. Instead, mineralogical identification needs to be coupled with physical flow testing in order to identify the risk.

If good quality data is acquired the risk of fines migration damage or excessive fines production can be identified and in some cases, appropriate mitigation against fines migration can be adopted. Several cases from oil and gas production wells and water injection wells will be used to illustrate best practice and identify the consequences of inadequate testing.
Development of a Dynamic Model for Drilling Fluid's Filtration: Implications to Prevent Formation Damage
Authors: VasheghaniFarahani Mehrdad , Soleimani Rasa , Jamshidi Saeid , Salehi Saeed
Published: June 2014

Drilling mud plays an important role in drilling operations. Forming a thin layer called mudcake is one of these roles which prevents the aquatic phase of drilling mud called mud filtrate from penetrating through the reservoir rock and therefore reduces the damage caused by that work. So knowing about the mudcake characteristics such as thickness, solid contents and also filtration rate of mud filtrate will help the drilling engineer.

Factors affecting filtration process are time, temperature and pressure. In this paper, a mathematical model will be presented which estimates mudcake thickness and filtration radius in both static and dynamic conditions with consideration a radial system at constant temperature conditions. The mudcake thickness and permeability variation with time are also considered in the dynamic model.
Particle Size Distribution Measurement Techniques and Their Relevance or Irrelevance to Sand Control Design
Authors: Zhang Ke , Chanpura Rajesh A. , Mondal Somnath , Wu Chu-Hsiang , Sharma Mukul M. , Ayoub Joseph A. , Parlar Mehmet
Published: June 2014

Sand particle size distributions (PSD) are used for various purposes in sand control: decision between various sand control techniques, sizing of the filter media (sand screens and/or gravel packs) through either rules of thumb or physical experiments or theoretical models. PSD of formation sand samples are also often used to generate "simulated" formation sand for laboratory experiments. The two most commonly used techniques for PSD measurements are sieve and laser, while some engineers use one technique for no obvious or justifiable reasons, others use both techniques for measurements and don't know what to do with the data when significant differences exist in PSDs obtained from each technique. Although the inherent limitations of, and the differences between, these two techniques as well as other factors impacting the measurements are well known, a systematic study as to what is relevant to sand control and why, is lacking.

In this paper, we critically review the current practices in PSD determination, use (and misuse) of the information obtained from these measurements, propose a methodology towards determining what is relevant, when and why, and present initial experimental results that support our conclusions.
Field Treatment to Stimulate an Oil Well in an Offshore Sandstone Reservoir Using a Novel, Low Corrosive, Environmentally Friendly Fluid
Authors: Nasr-El-Din H. A. , Dana H. , Tomos V. , Stanitzek T. , de Wolf C. A. , Alex A.
Published: June 2014

Acidizing in sandstone formations is a real challenge for the industry. Fines migration, sand production, and additional damages due to precipitation are some of the common concerns with sandstone treatments. Furthermore, the complexities of sandstone formations require a mixture of acids and loadings of many additives. The environmentally friendly chelating agent, glutamic acid N,N-diacetic acid, GLDA, was successfully used to stimulate deep gas wells in carbonate reservoirs. It was extensively tested in the lab to stimulate sandstone cores with various mineralogies. Significant permeability improvements were reported in our previous papers over a wide range of conditions. In this paper, we evaluate the results of the first field application with a fluid based on this chelating agent to acidize an offshore, sour oil well in a sandstone reservoir.

The field treatment included pumping a preflush of xylene to remove oil residues and any possible asphaltene deposited in the wellbore area, followed by the main stage that contained 25 wt% GLDA, a corrosion inhibitor, and a water wetting surfactant. The treatment fluids were displaced into the formation by pumping diesel. Following the treatment, the treatment fluids were allowed to soak for 6 hours, then the well was put on production, and samples of flowback fluids were collected. The concentrations of key cations were determined using ICP, and the chelate concentration was measured utilizing a titration method using ferric chloride solutions.

Corrosion tests conducted on low carbon steel tubulars indicated that this chelate has low corrosion rates under bottomhole conditions. No inhibitor intensifier was needed. The treatment was applied in the field without encountering any operational problems. A significant gain in oil production was achieved without adversely impacting the water cut, causing sand production, or fines migration. Analysis of flowback samples confirmed the ability of the chelating agent solution to dissolve various types of carbonates, oxides, and sulfides, while keeping the dissolved species in solution without causing unwanted precipitation. Unlike previous treatments conducted on this well, where 15 wt% HCl or 13.5/1.5 HCL/HF acids were used, the concentrations of iron and manganese in the flowback samples were negligible, confirming the very low corrosion rates of well tubulars when using GLDA solutions.
Analyses of Processes, Mechanisms, and Preventive Measures of Shale-Gas Reservoir Fluid, Completion, and Formation Damage
Authors: Civan Faruk
Published: June 2014

A comprehensive review and modeling of the natural and induced formation damage processes and their governing mechanisms involving the various aspects of gas-bearing shale reservoir formations is presented. The investigation and modeling efforts are carried out in several steps. First, the damage potential of shale formations containing large quantities of clay and nonclay inorganic, and organic materials, and natural fractures filled with cement and other debris is delineated. Second, the thermal, chemical, and stress interactions between the drilling and fracturing fluids of frequently used types are described. The various relevant processes and their fundamental mechanisms, including under/over balanced drilling, fracturing fluid disposition and retainment, wettability and nonequilibrium fluid transmission and spontaneous imbibition, swelling and fluidization, gas blockage occurring in extremely-low permeability shale porous media, are reviewed. These processes are described by phenomenological rate processes and the resulting modeling equations are solved simultaneously by a finite-difference-based numerical method. A number of representative case studies are considered and solved numerically. The results provide valuable insights into the nature of the shale-gas reservoir formation damage, indicating the significant roles of the different orders of magnitude rate processes and the thermal, chemical, and stress shocks causing formations damage during drilling, completion, and production. It is demonstrated by various numerical results that we can take advantage of the significant differences between the rates of occurrence of the adverse processes to effectively control, minimize, and/or prevent the shale-gas reservoir formation damage. This provides a scientifically-guided protocol for mitigation of gas-bearing shale formation damage.
Reduced Models for Description of Invasion Zone Geomechanics
Authors: Bocharov Oleg , Seryakov Alexander
Published: June 2014

This paper presents a coupled poroelastic model describing rock matrix deformation and two-phase filtration flow. The model has been derived based on mechanical principles of interpenetrated continuum and includes conservation laws written for the mixture components and constitutive equations in a form of the generalized Hook's law. The system has at least two spatial scales that define small quantity - scales ration. The small parameter decomposition has been utilized to obtain a series of approximate model corresponding to the special deformation condition. The zero-order approximation describes porous media with invariant volume. One also has obtained and analyzed an analytical solution in cylindrical coordinates for the zero volumetric deformation. The periodicity along radius stresses and pore pressure distribution in this solution demonstrate a possibility of disruption zones appearances not only at the borehole wall but also at some distance deeper in the rock. Its first-order approximation under a compact phase incompressibility assumption produces a generalization of the Buckley-Leverett two-phase filtration model with porous space deformations taken into account. The reduced poroelastic models presented enables a quick solution for mechanics and fluids-dynamics problems of invasion zone.
Experience of Carbonate Acidizing in the Challenging Environment of the Volga-Urals Region of Russia
Authors: Kayumov Rifat , Konchenko Andrey , Bairamov Alexey , Klyubin Artem , Levanyuk Olesya , Chikin Andrey , Firsov Vladislav , Nikulshin Evgeniy
Published: June 2014

The Volga-Urals basin is one of the largest oil-producing regions in Russia. Orenburg region is essential part of Volga-Urals basin and it represents most of the challenges encountered in the other parts of the basin. More than half the wells produce exclusively from carbonate formations and require periodic acidizing treatments to maintain economic production. Carbonate stimulation treatments are usually based on pumping of hydrochloric acid into the formation with use of special diverters to maximize zone coverage by acid treatment. Some of the formation properties in Volga-Urals basin create additional challenges for successful acidizing treatments, including significant reservoir pressure depletion, high water cut, formation heterogeneity with high- and low-permeability strikes, low reservoir temperature, crude with tendency for emulsion and sludge creation, and enormous thief zones created by previous acidizing treatments. In many cases, uncertainties in the formation properties make the stimulation more complex.

Carbonate stimulation practices in the Orenburg region have continuously improved during the last 6 years. First, degradable balls and polymer self-diverting acid were introduced to improve zone coverage. Later, viscoelastic self-diverting acid was added to eliminate damage associated with the polymer, and a viscoelastic selective diverter was used to minimize the probability of an increase in water cut after the treatment. Finally, foam was placed as a diversion agent, with and without coiled tubing (CT), to account for reservoir pressure depletion and help in post-acidizing flowback. Many lessons were learned, resulting in recommendations for use of various technologies at different reservoir and wellbore conditions.

In addition to the recommendations for technologies, a quality assurance and quality control (QAQC) standard was developed and implemented for acidizing treatments. Moreover, laboratory work such as core flow testing and proppant embedment tests has been undertaken to clarify post-treatment aspects.

Most fields in the Orenburg region are old, which implies that quality of well candidates became worse from year to year. However, with continuous improvement in stimulation practices and rigorous quality control we manage to maintain production at economic level and even increase work scope compared with previous years. This paper presents the experience gained during the 6-year of acidizing treatments in Orenburg region with lessons learned, and best practices adopted.
Challenging the Economic Limit in Mature Fields by Hydraulic Fracturing of Wet Producers
Authors: Rachid R. , Milne A. , Ali S. , Ramones M. , Jimenez J.
Published: June 2014

In Ecuador there are mature subhydrostatic sandstone reservoirs that have lateral water drive or that are located close to the oil/water contact. With time the water saturation has increased and water breakthrough is common in high-permeability streaks, causing the water cut to increase substantially. In these fields the challenge is to increase oil production and recoverable reserves through stimulation without increasing the water cut. For this reason, until recently, hydraulic fracturing was not considered a viable option. Although conventional acid treatments increased oil production, they also increased the water cut, sometimes making the production uneconomical. To overcome this, either acid treatments with diverter stages are used to selectively stimulate the oil-saturated intervals or relative permeability modifiers are used to limit water production. However, these have not proved to be reliable solutions.

To hydraulically fracture wet producers, a linear fracturing fluid was introduced. The fluid is formulated with low concentrations of a disproportionate permeability modifier (DPM) or a relative permeability modifier (RPM), and guar polymer creates a pseudoviscoelastic disproportionate permeability modifier (VDPM). The VDPM reduces the effective permeability to water in the fracture faces, and the relatively low viscosity of the fluid limits the net pressure and the risk of fracture height growth, without compromising proppant transport. The viscosity and leakoff control of the fluid can be adjusted as a function of the formation properties, leak-off and stress profile.

The first hydraulic fracturing campaign of eight wells using the VDPM fluid was in the Hollin formation, which has a strong aquifer below it and in some cases a lateral aquifer. Typically, the upper section produces oil and the lower section is water saturated; the distance between the two sections is 5 to 25 ft. On average the oil production increased threefold and the water cut was not increased after the fracturing job, in spite of the proximity to the wet zone. While the results of matrix treatments with RPMs in wet producers are notoriously mixed, hydraulic fracturing with a VDPM fluid has proved a reliable means to selectively increase oil production in the presented case. This has had a very positive impact on the economics and reserves recovery in these marginal mature fields.