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Collaborating Authors
Drilling Fluids and Materials
Abstract Different index parameters are used for quick assessment of mechanical properties of rocks in civil, soil and rock mechanical applications. These index parameters provide valuable information regarding material toughness, abrasion resistance, durability, strength, etc under different forces of interactions and environmental conditions. The sized bridging materials (SBMs) used in drill-in fluid design belongs to rock family and thus any rock mechanical parameters such as UCS, tensile strength, shear strength, etc can be used for mechanical characterization of SBMs to select the best and reject the worst. However, due to granular size of the SBMs with a typical particle size of below 2000 microns, the conventional rock mechanical parameters are not applicable for assessing the toughness and durability of SBMs. Hence, an appropriate index parameter is needed to assess the toughness and durability of SBMs to select the best SBMs for superior drill-in fluid formulation. This paper describes an index parameter defined as Bridging Material Stability Index (BMSI) for quick and reliable assessment of the toughness and durability of SBMs. Empirical results indicate strong relation of the index parameter with the quality of the SBMs and thus provide a quantitative means for quality control and quality assurance of SBMs. Statistical analyses of the coefficient of variation of BMSI indicate significantly lower coefficient of variation compared to common rock mechanical parameters such as compressive strength, tensile strength and shear strength parameters. The application of the index parameter will allow selecting the best and rejecting the worst SBMs for superior drill-in fluid formulations and thus expected to play a pivotal role in reducing formation damage and enhancing well productivity.
- North America > United States (0.93)
- Asia > Middle East > Saudi Arabia (0.47)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
Abstract Flat Rheology Invert Drilling Fluid (FRIDF) has been successfully used for deepwater drilling due to its outstanding performance in providing excellent hole cleaning, temperature-independent rheology profile, good barite sag control and good ECD control. The high performance is achieved by using correct combinations of emulsifier, wetting agent, rheology modifiers and supplementary viscosifiers. Because of the multiple products used, the FRIDF can be complex to engineer and manage. An improved and simplified flat rheology system has been developed to aid in the field engineering and ease of system maintenance without sacrificing fluid performance. The newly developed flat rheology system utilizes a single emulsifier component to provide dual functions of emulsification and surface wetting. This helps to improve emulsion stability and enhance thermal stability and fluid lubricity. The system can be formulated for deepwater applications with mud weights up to 18.0 lb/gal and temperatures up to 350°F. In addition, the system uses a new rheology modifier that provides a temperature-independent rheology profile for hole cleaning, barite suspension, ECD management and lost circulation control. Recent field trials indicated that the new system is easy to maintain and provides good fluid performance in terms of drilling rate, ECD management, lost circulation control and hole cleaning. Even when the system was contaminated with a severe saltwater flow, there were no fluid-related problems before the synthetic/water ratio was restored. The new fluid system exhibited flat rheology profiles and non-progressive gel structures. Hydraulic modeling showed excellent hole cleaning with low ECDs and breaking-circulation pressure. This resulted in a noticeable reduction of lost circulation potential in lost circulation prone areas. The performance of the new flat rheology system (NFRS) also will be compared to the current system to demonstrate some advantages of the new system.
Abstract The primary goal of operators and drilling contractors is to safely, economically, and efficiently drill more holes in less time to enable completion and production operations to begin. However, unplanned events that introduce unexpected and costly delays often occur during the drilling phase. These unplanned events must be dealt with in a timely and effective manner to enable drilling operations to continue. One event type common to drilling operations is the need to set openhole cement plugs for plug back, kickoff, or curing loss-circulation intervals. The time and cost associated with spotting cement plugs directly impacts well operations and is often classified as nonproductive time (NPT) by operators, especially if initial plugs fail to achieve the purpose for which they were set. Placing cement plugs in today’s complex wellbores and the increased costs associated with these operations necessitates the use of plug designs and procedures that have been designed to reduce risk and utilize new technologies and documented processes to achieve the desired results. Reviewing current practices for deploying new technology helps to optimize overall plug cementing operations in both vertical and extended-reach wellbores. However, there are a number of challenges associated with setting cement plugs in an openhole well. Most importantly, drillpipe can become differentially stuck across a lost-circulation zone, and the plug can become contaminated with the intermixing of the mud, resulting in inadequate isolation or insufficient strength. An innovative tool (Rogers et al. 2004) has been designed to meet the challenges associated with setting cement plugs. The tool connects sacrificial/drillable tubing to the drillpipe and allows an operator to trip into the well and spot the cement plug across the problematic zone. Once cement is placed, the tool is disengaged and the operator trips the drillpipe out of the hole, leaving the cement plug and tubing undisturbed. The sacrificial tubing can be drillable; therefore, the operator can drill through the plug or commence other operations, as required. This paper discusses the challenges operators face when setting cement plugs and how risks and NPT are reduced with this innovative plug-setting process and tool. Well examples are documented from case histories to illustrate the success and lessons learned.
- Europe (1.00)
- Asia (0.68)
- North America > United States > New Mexico (0.29)
- North America > United States > Texas (0.28)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- (3 more...)
Abstract As wellbores continue to be drilled deeper and farther than ever before, the need for improved drilling fluid systems that optimize fluid performance in harsh and challenging environments is at its highest demand. Invert emulsion fluids are frequently chosen due to their high performance and low risk in various applications. Invert fluids are a particularly good choice when dealing with extreme environments, such as those with surface temperatures as low as - 26C (-15F) or those wells having bottom hole temperatures in excess of 250C (485F). Invert fluids are typically the preferred choice over water-based alternatives in deepwater and extended reach wells because of their inherently better lubricity and improved wellbore stability. The most important component of the invert fluid is the surfactant package, which maintains the solids in an oil-wet state, assists in filtration control, and stabilizes the internal phase of the fluid. The latest developments in surfactant chemistries designed for invert emulsion fluids has resulted in a significant improvement in the performance of these fluid systems. Newly developed systems allow for simplified engineering due to formulation flexibility across temperature and density, high internal phase ratios with low viscosity, emulsion stability at temperature extremes, and a greener chemical profile. Each of these has a positive effect on drilling economics, environmental compliance, logistics, and health and safety. This paper will review the new surfactant technologies, describing both their advantages and drawbacks from the standpoints of drilling performance and applicability, showing example data leading to these conclusions. The authors will also review the recent field usage of the surfactants described.
- Asia (0.68)
- North America > United States (0.29)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.32)
Abstract Barite sag and poor hole cleaning are not problems; they are symptoms of well control and stuck pipe problems. Issues with barite sag and hole cleaning are routinely encountered while drilling high pressure high temperature (HPHT) wells. Maintaining optimal mud rheology in HTHP conditions (350°F+) can be very difficult. Adding organo-clays or low gravity solids (LGS) to boost rheology can lead to high equivalent circulating densities (ECD) and low rates of penetration (ROP). The new HPHT organic rheology modifier (ORM) imparts optimal rheological properties to low, medium and high density clay-free invert emulsion fluids (IEF). Clay-free systems have previously demonstrated superior gel strength and rheological profiles over conventional organo-clay and lignite treated fluids. Although significant improvement in these systems seemed unlikely, this was accomplished with the new ORM chemistry. These IEFs exhibit enhanced low shear rheology (even at 9.0 ppg) with lower or similar plastic viscosity (PV) values when compared to IEFs formulated without the new HPHT rheology modifier. When tested at up to 400°F and 18,000 psi, the IEFs formulated with ORM show similar or higher low shear rheology with low PV than under ambient condition. A good low shear rheology implies better hole cleaning and sag control. A low PV improves ECD control. Treatment with ORM imparts fragile gel characteristics to 9.0 to 18.0 ppg clay-free IEFs. The rapid gel-to-flow transition helps to minimize surge and swab pressures and reduce mud losses. The new HPHT rheology modifier with a biodegradability of 67% in 28 days also stabilizes the IEF and provides comparatively low fluid loss values. It also eliminates the need to add LGS to boost rheology. The paper presents experimental data demonstrating both the environmental and rheological performance of the HTHP rheology modifier as well as comparative data from the conventional clay-free fluids without the ORM.
- North America > United States (0.47)
- Asia (0.28)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > HP/HT reservoirs (1.00)
Abstract Shale-gas plays and other unconventional resources have gained significant importance worldwide. Historically, synthetic-base drilling fluids (SBM) are used in these plays when no environmental concerns are in place and are preferred when wellbore stability is necessary. In this paper, we study the use of an improved water-base drilling fluid (WBM) that is simple in formulation and maintenance that shows excellent rheological properties, maintains wellbore stability, and a good environmental profile. A combination of well-known and economically affordable materials is combined with new technology to achieve desired rheological properties and wellbore stability. The use of nanoparticles to decrease shale permeability by physically plugging nanoscale pores holds the potential to remove a major hurdle in confidently applying water-base drilling fluids in shale formations, adding a new advantage to the studied fluid. Silica nanomaterials were investigated for this purpose. Due to their commercial availability, these materials can be engineered to meet the specifications of the formation. Characterization of the nanoparticles was completed with Transmission Electron Microscopy (TEM), dynamic light scattering, and X-ray photoelectron spectroscopy. Rheological properties and fluid loss are studied together with other important properties such as shale stability and anti-accretion properties. The authors will describe new laboratory methods used to investigate these properties, from a modified API fluid loss test to the Shale Membrane Test that measures both fluid loss and plugging effects and illustrate additional future research that includes adding reactive species, and anchoring them to the pores, thus stabilizing the shale further.
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (10 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
Abstract Ultra high temperature, high pressure (uHTHP) conditions have a different definition depending on the region and the operator and Service Company. In this paper the definition used for uHTHP fluid performance is that of a fluid able to perform above 500°F and 30,000 psi. This paper describes the development of innovative drilling fluids specific to these well conditions. When bottomhole temperatures exceed 400°F, the design and engineering of drilling fluids can be challenging. Drilling fluids that destabilize can cause a variety of fluid control problems that could lead to drilling and completion issues. With Invert emulsion fluids, the major challenges encountered under these conditions are related to the thermal degradation of the emulsifier and wetting package that can lead to gelation and syneresis. Another challenge is fluid loss which is related to the emulsion stability and to the degradation of the fluid loss control additives. Finally, efficient control over the rheological properties – critical to the success of any well - can also be challenging, where effects from emulsion instability, filtration control degradation and rheology control additive degradation are coupled with increases in drilled solids, rapidly leading to rheological instability. This can manifest itself as high fluctuating rheologies and gelation, or loss of rheological properties that can give rise to sag of weight material, both potentially leading to associated well control problems. The paper describes the development of the new fluid system designed for such uHTHP environments, highlighting the chemical differences and compares the test data of the system with more conventional HTHP invert emulsion fluids. Data is presented showing the stability and performance of the new fluid over extended exposure to temperature >500°F, demonstrating tolerance to various contaminations and showing the rheological behavior and stability to 600°F and 40,000 psi.
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
Offshore Drilling & Well Testing Of A HPHT Gas Well: A Case Study
Shah, Prerak H (Gujarat State Petroleum Corporation Limited (GSPC)) | Pandya, Harsh T (Gujarat State Petroleum Corporation Limited (GSPC)) | Sharma, Harsh (Gujarat State Petroleum Corporation Limited (GSPC)) | Saxena, Arpit (Gujarat State Petroleum Corporation Limited (GSPC))
Abstract With exploration in harsh environments and consequent high pressure and temperature conditions, the calculation of reservoir properties has become complex and thus the changes in pressure transient response need to be understood and appreciated by taking appropriate challenging measures. The paper deals with the various challenges arising when dealing with the drilling and testing of HPHT gas wells with Hydrogen sulfide and Carbon dioxide, located in Krishna Godavari (KG) Basin and the difficulties faced while executing it. The paper focuses on the experience while drilling the reservoir with a different mud program and mechanical failure caused by HPHT conditions & highly corrosive environment. The paper also highlights the preference of SOBM over WBM while drilling the reservoir section. It also describes the learning process as the exploratory well campaign progresses from one well to other. It briefs about the challenges while performing MDT as per the program in these high temperature environment. The paper briefs about the decision involved in selection of proper grade tubing, elastomer, packer, flowhead equipments, DST tools & explosives in this HPHT environment along with Hydrogen sulfide & Carbon Dioxide. In any gas well testing, exhaustive amount of data over the requisite period of time are necessary; data redundancy necessitates redressing of equipments. The biggest challenges faced by industry are high temperature rather than high pressures, so making metallurgy an important basis of consideration. It also highlights about the method followed during correlation of prospective zones using different logs. The paper discusses the unexpected results and observations obtained during execution of our program and the lessons learnt from it.
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.30)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Well Drilling > Drilling Equipment (1.00)
- (3 more...)
Abstract OIL INDIA LTD operates a number of oil and gas pipelines in the fields of Upper Assam. The total volume of oil handled annually is around 4 MMT. The crude oil produced is generally of waxy nature with a specific gravity of 0.87, having a high pour point of 25 deg.C and viscosity from 3.5cp till 6cp. Over the period of years a number of methods have been developed with field and laboratory data to design, construct and maintain the pipelines including the flow lines from the well pads to the oil collection centers. At present an effective method to handle the highly paraffinic crude is the use of water bath type heaters with a heating range till 80 degree centigrade. Indirect heaters together or at times alone are used with pour point depressants, commercial name being Maxdip 1500 which is a vinyl acetate co-polymer. During our design of new pipelines over and above to the codes of API 31.4/31.8 for pipeline design we have incorporated certain additions and deletions’ as per our requirement of handling the Assam oil. Certain redesign has also been done in certain pipelines to handle very high paraffinic crude. The 8" Duliajan Digboi refinery crude oil delivery line is an example. Design modifications were done on the existing pipeline without effecting the refinery operations. For the Salmari field heavy oil, in-house design and maintenance efforts with combination of Merus rings and heating through bath type indirect heaters has enabled a trouble free operation. To overcome the problem of congealing in well flow lines a number of methods like steam injection, heating of the crude oil and gas and use of high pressure hot oil pumps have been developed to redesign, re-modify the existing flow lines. Recently we had undertaken a pilot project to introduce a scrapper tool inside the closed circuit loop of the well flow line. With the above endeavors developed in-house we have been able to maintain modify design and construct (lay) pipelines in our operational area with almost 100% flow assurance
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (0.91)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (0.84)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Piping design and simulation (0.61)
Abstract An offshore operator in Malaysia detected an unexplained annulus pressure increase after completing a large-bore gas production well. A leak detection tool was run on an electric line tractor and located leaking tubing connections at 333 m and 394 m MD. This led the operator to recomplete the well. The operator chose to close a fluid loss isolation valve at 1800 m MD. Because an electric line tractor, hydraulic stroking tool, and key tool were already onboard the platform as a contingency to open the valve, this suit of technology was chosen to close the valve. The toolstring was configured with a 4.625" key pad to fit into the sliding sleeve of the valve and run in the hole. The tractor was activated 146 m above the valve and then driven down to the valve where a depth correlation was made. Then the toolstring was placed with the key extended until it reached the recess area above the shifting profile. The piston of the hydraulic stroker was extended with the key pads expanded and located the shifting profile. Next, the hydraulic stroker was activated to stroke up and thereby closed the ball valve. The valve was closed in 15 hours from rig up to rig down, including 2 hours of inflow test. This was the first time such a valve has been closed on electric line in Asia Pacific and the operation proved the viability and efficiency of the technology. Importantly, the operator did not kill the well and saved significant costs by cutting the time in half compared to a workover. This paper will present the learning from the operation while discussing this newly adopted approach and the benefits it offers to the industry.