bluuebunny/crossref_metadata_2025 huggingface dataset:
An Alternative Systems Approach to the Successful Execution of Deepwater Drilling Programs
Authors: Bouska R. , Jeffery C. , Ramnarace D. , Brinkman C. , Jorgensen J. , Vasylyev S.
Published: June 2014

The increasing complexity of deepwater Bottom Hole Assemblies (BHAs) requires a complete systematic approach to each phase of the drilling process: pre-job planning, execution and evaluation. This approach was successfully applied to a recent multi-well project in the Gulf of Mexico, whose vertical 12¼ in x 13½ in sections were historically plagued by shocks and vibrations while drilling. The root cause of inefficient drilling performance could not be accurately determined based on drilling data, but severe vibrations resulted in multiple downhole tool and BHA component failures.

With the implementation of a complete, holistic approach to the drilling system, the drilling proceeded with no downhole tool failures and a significant reduction in drilling time and costs. The key to these successes were the multistage preparation process that was utilized, which included:

A detailed analysis of all the offset data available for the same field and for fields with similar lithologies and formation properties. A rock strength analysis based on Logging While Drilling (LWD) data and Compressive Confined Strength (CCS) measurements. A bit and reamer matching process taking into account CCS, lithology, directional profile and cutters layout while matching the performance criteria for both drill bit and underreamer.

Advanced tools and technology, including critical speed analysis and asymmetric vibration tool placement, were applied and supported by high-frequency downhole dynamics memory data with corresponding post-run drilling performance and vibration analysis. Some of the major contributors to the successful application were the designed-for-purpose engineered BHA and optimized operational environment.

This approach can be applied to borehole enlargement wells, as well as vertical, directional and horizontal wells. The analyses of the measurements gathered during all phases of the project, including a description of the obtained results, are discussed in detail. The results highlight a consistent improvement in drilling performance for the 12¼ in x 13½ in well section, where vibrations were the main limiting factor. Efficient drilling performance is achieved by implementing this complete approach to the deepwater drilling system and these engineering solutions for vibration mitigation, increasing ROP and improving BHA integrity and wellbore quality.
Safer Tripping Through Drilling Automation
Authors: Chmela Bill , Gibson Nicholas , Abrahamsen Egill , Bergerud Ronny
Published: June 2014

Automation consists of the use of control systems to control processes, reducing the need for human intervention. There has been considerable progress made in automating key tasks on the drill floor (i.e. mechanization), and in providing control of the weight on bit and bit rotation, etc. (e.g. Dupriest, 2005) to optimize the rate of penetration. In this paper we look at a stepwise implementation of adaptive drilling automation that responds to changing conditions in the wellbore.

Within well construction, one specific process that may be well suited to this adaptive automation is the tripping of drillpipe or casing into or out of the well. Tripping operations today are guided by pre-drill analysis to determine safe tripping speeds and require the driller to react to changing downhole conditions to avoid problems such as swab, surge, or hole collapse. In this paper we describe a stepwise approach to partial adaptive automation of the tripping operation. The stepwise approach consists of continuously performing engineering-while drilling calculations to determine the dynamic hydraulic pressure profile variations within the wellbore at all depths for any driller-induced string motions or pump rates. Next we use these calculations to determine safe operational envelopes for the drilling machinery (accelerations, decelerations, rates and velocities), helping the driller to trip pipe in or out of the well while ensuring that the full wellbore hydraulic pressure profile always stays within the prescribed safe geopressure window based on current conditions. Finally, we reach the automation step where the operational envelopes guide the automated control of the drilling equipment.
Development and Testing of Stick/Slip-Resistant PDC Bits
Authors: Schwefe Thorsten , Ledgerwood L. W. , Jain Jayesh R. , Fuselier Danielle M. , Oueslati Hatem , Endres Lance
Published: June 2014

Stick/slip vibrations are known to cause damage to drill bits and other drilling system components. Recent investigations reported by the authors determined that the design of polycrystalline diamond compact (PDC) bits has a significant influence on stick/slip behaviour of the drilling systems. Among various bit design methodologies, a depth-of-cut (DOC) control technique has emerged as an effective way of mitigating bit-induced stick/slip. The research reported in this paper aims at enhancing this technique to accurately identify the optimal application of DOC control for maximum reliability and performance.

A comprehensive testing program on a full-scale research rig was undertaken to characterize the optimal type, positioning, and extent of DOC control required for mitigating stick/slip. Several PDC bits incorporating strategically configured DOC control elements were designed and tested. The stick/slip tendencies of bits were determined based on diagnostics from downhole drilling dynamics monitoring devices while the surface operating parameters were varied in a controlled manner.

Test results indicated that certain DOC control characteristics were the most effective in mitigating stick/slip. While under-application of DOC control did not mitigate stick/slip, over-application reduced performance without mitigating stick/slip. Formation type played a major role in instigating stick/slip, and was a significant factor in designing DOC control.

The paper presents analysis details and proposes design guidelines based on testing in multiple formations within three research wells. These design guidelines are also supported by field evidence from the North Sea, where statistics on many bit runs indicate superior performance with properly tuned DOC control.
Relief Well Planning
Authors: Flores Vanessa , Dailey Penny , Todd David , Mathur Rohit , Donadieu Brian
Published: June 2014

Relief well planning can be a critical safety measure, ensuring readiness and rapid response in the event of a catastrophic blowout that threatens human life and the environment. Recent regulatory changes in the oil industry have spurred a demand for extensive relief well planning for shelf and deepwater wells around the world. This paper discusses well planning, trajectory design, and drilling as it applies specifically to relief wells.

A relief well is drilled adjacent to an existing well that has suffered an uncontrolled release of pressurized hydrocarbons. From an operational standpoint, a relief well is drilled only if surface intervention or capping attempts are taking too long or have failed to stop the flow. The goal of the relief well is to divert the pressurized hydrocarbons up a new wellbore in a controlled manner or to kill the blowout well with heavy mud and secure it with cement. For either remedy to succeed, precise interception of the existing wellbore becomes a key component in relief well design. This, in turn, makes the entire relief well planning component a very crucial and challenging aspect of the well design.

This paper focuses on five phases of relief well planning:

Surface location selection, including shallow hazard assessment, metocean considerations and rig logistics. Selection of drilling, evaluation, ranging and interception tools. Directional trajectory design utilizing a bottom-up approach. Project execution (drilling operations). Intercepting the well considering cased hole, openhole or the reservoir section of the blowout well.

The United States Bureau of Safety and Environmental Enforcement (BSEE) requires all operators to provide documentation demonstrating their capacity to drill a relief well. Operators in the Gulf of Mexico must submit the surface location for a relief well along with their application for a permit to drill. Two locations are generally identified, and relief well paths are planned for each at every casing point prior to an interval where hydrocarbons may be encountered. As many factors can change while drilling, the planned relief well paths would require appropriate modification, but the initial plans prove feasibility and provide a basis upon which a plan to an actual wellbore could be quickly designed. The regulations ensure safe planning and execution in response to a hazardous situation, and they are in the process of being adopted by worldwide government agencies.
A New Continuous Flow System (CFS) for Managed Pressure Drilling
Authors: Cunningham Justin , Bansal R. K. , George Geoff , De Leon Eisenhower
Published: June 2014

Continuous circulation of drilling fluid offers many benefits, including increased control of downhole pressure in relation to pore and fracture pressures along with enhanced wellbore cleaning. Although the concept of continuous circulation has been known to the industry for a long time, it has gained significance in recent years with real-time downhole pressure monitoring and control. Continuous circulation provides an uninterrupted data stream from downhole sensors and surface equipment even while making a connection, thereby never losing downhole pressure.

Weatherford has developed a continuous flow system (CFS), including subs that crown the top of a drillpipe stand and an automated control system that switches mud flow between the top drive and the side flow port. During conventional drilling operations, CFS subs are passive drillstring components. When a new stand needs to be added, a CFS sub connected to a stand already drilled into the well is positioned in the rotary table, and a clamp carrying a side flowline is attached to it. Once the clamp has been securely attached, rig hands can move off the rig floor and conduct the rest of the operation from a remote control panel. At this point, the CFS sub works like a three-way valve. When a sleeve inside the CFS sub is pushed upward, it opens a side flow port on the sub and simultaneously closes an internal valve to cut off flow from the top drive. With concurrent operation of mud valves on a manifold skid, mud flow is redirected from the top drive to the side flow port before breaking the top-drive connection. Mud flow is also directed back to the top drive after adding a stand. The CFS can be used during trip-in and trip-out operations in an almost identical manner.

Significant advantages of the CFS are easy implementation into the rig flow loop, automated switching of flow from the standpipe to the side entry port and back from a remote location, high consideration for personnel safety, limited impact on connection time, and a small footprint on the rig floor.
Instrumented Motors Prove Crucial in Unconventional Well Placement
Authors: Wright Anthony , Snyder John
Published: June 2014

Near-bit, instrumented motors are a transformative technology used for unconventional well placement. Near-bit sensors are located closer to the bit compared to traditional measurement while drilling (MWD) sensors, which are normally >20 ft behind the bit, thus allowing the opportunity for exiting thin bed formations before a formation change can be observed on the logs. These tools are also instrumental when choosing the formation tops for each new boundary drilled. The gamma-at-bit-inclination sensor system provides at-bit azimuthal gamma ray and inclination measurements for improved geosteering and optimum well placement. This paper describes the geosteering capabilities of a newly released 6 3/4-in. sensor in different formations.

In a single run, the gamma-at-bit-inclination sensor system successfully delivered a hole section of 4,952 ft (2,248 to 7,200 ft) in 43.5 drilling hr, with an average rate of penetration (ROP) of 114 ft/hr in depleted shale and sandstone formations on the Gulf of Mexico (GOM) continental shelf, eliminating additional bottomhole assembly (BHA) changes; a 4,043-ft (7,442 to 11,485 ft) lateral in 23.5 drilling hr with an ROP of 172 ft/hr in Oklahoma City (OKC), Oklahoma; and 4,781 ft (479 to 5,260 ft) in 37.75 drilling hr at an ROP of 127 ft/hr in the Woodford shale of the Mississippi Lime, with zero non-productive time (NPT) or health, safety, and environment (HSE) incidents.

The use of near-bit, instrumented motors allows remaining in the zone of unconventional plays longer. To date, a total of more than one million feet has been drilled using a smaller near-bit, 4 3/4-in. instrumented motor, and running with larger-sized tools has proven successful. Instrumented motors previously had limited drilling application; however, with the geosteering requirements for unconventional well placement, a greater range of applications for the measurements provided by the near-bit, instrumented motors has been identified.
Application of Real-Time Process Control and Engineering Software Simulation in Foam Cementing
Authors: Dooply Mohammed , Elhancha Anouar , DeBruijn Gunnar , Gubanov Evgeny , Voloshchuk Maxim
Published: June 2014

Foamed cement operations not only require a solid knowledge of the foam quality during placement, but also good control of nitrogen injection throughout the operation. These two factors ensure optimum well control during placement and provide well integrity after placement completion.

A real-time foamed cement process control system is capable of handling dramatic changes in the cement slurry pump rate which allows for delivering quality foamed cement with the designed proportions of gaseous nitrogen and surfactants. The process-controlled system can also perform operations with more than 200 stages of varying nitrogen ratios to provide a near-constant density column of foamed cement in the wellbore.

A dynamic compressible fluid placement simulator provides better understanding on the evolution of foam quality across the wellbore during the placement. The simulator computations take into account the influence of circulating pressures and temperatures on nitrogen compressibility. The simulator then evaluates the computed surface and downhole pressures and foam qualities throughout cement placement and after cement in place, and issues warnings whenever those parameters fall outside the design criteria at any time during the operation. Such feedback allows the engineer to adjust the design to meet the job objectives.

The combination of these two technologies effectively reduces the operational complexities on foamed cement operations, which will substantially increase the success rate and enhance well integrity. Several case studies of foamed cement operations performed in the Gulf of Mexico are presented in which the use of real-time process control and dynamic placement simulation provided successful job execution and proper cement placement.
Automated Planning of Procedures for Risk Mitigation and Efficiency
Authors: Molin Arthur , Kortenkamp David , Bonasso R. Peter , Schreckenghost Debra , Bell Scott , Kusy Kevin
Published: June 2014

To effectively manage drilling operations is an enormous challenge. The work must be carefully planned and scheduled, but unforeseen events may force changes in the plan at any time. An efficient plan of operation is vital to ensure that work is performed safely and efficiently, that risks are managed appropriately, and that the cost of the operation is controlled. Maintenance tasks must be performed on schedule; if necessary maintenance tasks are delayed the costs associated can balloon or health and environmental risks might arise. However, routine maintenance must be scheduled to minimize the impact on ongoing operations.

The National Aeronautics and Space Administration (NASA) is currently pioneering work on using automated planning and scheduling to manage the work performed during Extra-Vehicular Activities (EVAs) on the outside of the International Space Station (ISS). These EVAs are the most difficult activities performed by the astronauts on the ISS, and each one is planned to maximize efficiency and minimize risk. The time available for an EVA is strictly limited both by the life-support system and human endurance, and every minute must be utilized properly.

NASA is developing a technology for representing procedures, or the tasks that must be performed during the EVA. The procedures encode the time estimated for the task, the tools and equipment needed, any preconditions for the task to be performed, and also the state of the system at the end of the task. An automated planner has been developed that can take a high-level goal plus those procedures, and:

produce a plan of operation that attains the goal while ensuring the tools and equipment are available when needed, ensure limited resources such as oxygen are managed efficiently, ensure the safety equipment is not overloaded, and ensure that no performance rules are violated.

The system can track the usage of tools and equipment and automatically update inventory databases at the end of the EVA to represent changes in location, to simplify the beginning of the next EVA. In the event of unforeseen events, the automated planner can re-plan the remainder of the shift.

This planning technology developed for NASA has potential to improve the safety and efficiency of drilling operations. Risks associated with safety-critical activities can be reduced by validating the sequencing of these activities to ensure there are no missing steps or misconfigured systems that could lead to accidents. Compliance with safety policies can be improved by modeling these policies as constraints on how drilling activities should be performed. Logistics for drilling preparation and operations can be improved by automatically deriving the tools and equipment needed based on the tasks to be performed. This paper will describe the planning approach implemented for NASA, and will identify how that approach can be used to improve drilling operations.
Identifying and Surviving a 1500 ft Long Keyseat @18,000ft – A Case History and Lessons Learned
Authors: May Richard , Perez Carlos , Perdomo Andres , Jiménez Africa , Angel John , Salinas Nelson , Rodriguez Efrain , Angarita Camilo , Mierez Jose
Published: June 2014

The Bricol field is a naturally fractured reservoir, located in Southern Mexico primarily producing from a deep objective in the Upper Jurassic Kimmeridgian formation. The geological complexity includes fracturing, salt bodies, high pressure and temperature.

While drilling an HPHT directional well at 18,820 ft below an 11 ¾" drilling liner set at 13,763 ft, that required directional drilling with a 10 5/8" pilot bit, rotary steerable system (RSS), and simultaneously under reaming to 12 ¼", serious drilling operational problems were encountered. Severe hole drag in excess of 150,000 lb as well as high shock and vibrations were encountered that ultimately resulted in a drill string twist off, jeopardizing the success of the well.

After successfully fishing and recovering the twisted off drill string, a multidisciplinary team collaborated to find the root cause of the drilling problems. Wireline logs were run, including a six arm oriented caliper log, which identified a Keyseat in the wellbore, located between 16,733 ft – 18,275 ft (Length 1542 ft). A detailed review and evaluation of the wellbore conditions at that depth interval was performed in order to identify the root cause of this anomaly. The 12 ¼" hole section was successfully finished and the 9 7/8" liner was run and cemented

This paper will give a detailed description of the problems encountered and the unique solution that was developed to overcome problems on future wells, during the planning stage through sensitivity analysis to improve the trajectory. In cases where the trajectory cannot be modified we have recommended preventative actions to minimize drilling problems.
New Applications of Cementing Valve Technology for Gulf of Mexico Deepwater Operations
Authors: McNicol Jim
Published: June 2014

Deepwater wells face a myriad of challenges, amongst which are: narrow pore pressure-fracture gradient margins, salt sections and salt exits, cementing operations in relatively weak formations, management of annular pressure buildup (APB) in un-cemented annuli and well integrity assurance for life of well. New methodologies and a novel new stage cementing system has been developed to address these challenges.

In a recent Gulf of Mexico well, a 16" liner primary cement job secured the bottom of the section but did not cover sufficient height of the salt section to provide adequate zonal isolation and created an APB issue. A planned second stage cementing operation was performed using a new cementing valve that was tested to the same gas-tight regime as the V0 specification employed in ISO14310. Two cementing valves were run on the 16" liner string; one at the top, immediately below the liner hanger and one near the bottom. A drillpipe deployed cementing tool was RIH to shift the upper cementing valve open and pump a large quantity of cement down the annulus from the liner hanger to the top of cement left by the primary cement job; the upper valve was then closed and tested. Further operations, including logging verified the cement job integrity.

The paper will discuss the operation in detail and explain how performing a second stage cementing job "top-down" through a cementing valve, as opposed to conventional cementing circulation, resulted in full zonal isolation throughout the entire section; and eliminated many of the issues described before. The paper will present additional benefits such as fully filling the liner annuli to eliminate APB and improve well integrity for life of well. There will be an evaluation of future opportunities to improve zonal isolation in salt sections; create secure wells in areas of depleted sands; and access narrow margin areas of interest with low pore pressure-fracture gradient.
Combining MWD Ranging Technology and Gyro While Drilling (GWD) In High Inclination Wellbores Deliver Reduced Drilling Costs and Complexity without Compromising Safety
Authors: Duck C. H. , Beattie K. , Lowdon R. , McElhinney G.
Published: June 2014

The uncertainties associated with current wellbore surveying techniques can generate time consuming challenges when sidetracking around a fish at high inclinations. If the sidetrack is not planned with a significant safety margin and/or the bottom hole assembly does not include the proper amount of non-magnetic spacing then the MWD surveys of the sidetrack wellbore can be compromised significantly by external magnetic interference leaving the well to be drilled blind. One means of monitoring the approach between a drilling well and a secondary wellbore has been to use the MWD sensors to monitor for external magnetic interference. When monitoring the convergence of two wellbores in a close approach situation, the relative positions between the wells must be calculated. However, calculating the relative position between wells is a challenge when the inclination of the two wellbores exceeds 80 degrees.

This method increases safety while drilling. Using gyro while drilling eliminates the need to run wire line conveyed gyros, saving considerable expense. Gyro while drilling (GWD) allows data to be collected frequently while the drilling progresses, minimizing the risk of intercepting the fish without slowing the drilling process. Equally it is possible to be flexible in sidetrack trajectories as any attitude is available. There is no longer a need to steer by inclination only, improving efficiency in drilling operations.

This paper looks at a case study where a passive MWD ranging method uses both the output of the magnetic sensors from the MWD and the directional information calculated from an all attitude gyro while drilling tool. This allows the calculation of the spatial relationship (distance and direction), between the drilling well and the fish, at 90 degrees of inclination. As the drilling sidetrack and the fish are at 90 degrees inclination and the two wellbores are not parallel, a high inclination gyro must be used to calculate the azimuth required for passive ranging calculations. Since an electromagnetic target cannot be placed in the original hole, only a single entry ranging technique can be used. This tool combination allows the positional relationship between the drilling well and the fish to be continuously monitored until the collision risk has passed.
Reservoir Friendly Rigid Setting Fluid Arrests Lost Circulation While Minimizing Reservoir Damage
Authors: Savari Sharath , Whitfill Donald L. , Miller Matthew L.
Published: June 2014

Currently, many producing formations are carbonates and/or depleted sands that are characterized by highly permeable flow paths or vugs. Severe-to-total loss of drilling fluid in these formations is a major concern from both the drilling and reservoir damage perspectives. Conventional particulate lost circulation materials (LCMs), such as acid-soluble ground marble, might not effectively cure severe losses. Furthermore, because the application is in a producing formation, avoiding reservoir damage is a major criterion that any potential solution should satisfy. The "band-width" of available solutions that are both efficient and reservoir friendly is narrow, leading to both high cost and potentially risky drilling practices.

A possible solution is using an acid-soluble right-angle-setting composition (RAS-Co) that was developed to provide the industry with a more efficient solution for plugging and isolating producing zones that have high drilling fluid loss rates. RAS-Co is formulated from inorganic, nonhazardous powders and fluids mixed in fresh water or seawater. RAS-Co is engineered to be a low-viscosity (18 to 30 cp) fluid containing small particulates, which allows it to be mixed at the rigsite and pumped through any drillstring configuration. It is designed to react at a specific bottomhole circulating temperature (BHCT) in a consistent and controllable manner with a "right-angle" set. Once it is spotted/placed in the suspected loss zone, it helps eliminate further fluid losses and formation damage. The small particle size distribution acts as a pore-bridging material while in the fluid state, and the right-angle-set characteristic makes the material non-invasive to the formation and allows it to be easily drilled or removed with acid. It can be used in zones with up to 300°F circulating temperature and tolerates up to 50% contamination with water or drilling fluids.

This paper describes attributes of RAS-Co along with successful field applications that illustrate it is an effective solution for controlling reservoir damage by helping to stop severe lost circulation events.
Reservoir Simulation, Ion Reactions and Near-Well Bore Modelling to Aid Scale Management in a Subsea Gulf of Mexico Field
Authors: Mackay Eric J , Jordan Myles M. , Ishkov Oleg , Vazquez Oscar
Published: June 2014

This paper presents the findings of a study into the impact of reservoir flow behaviour on both the scaling risk at production wells, and the options for managing this scaling risk, for a deepwater sandstone reservoir in the Gulf of Mexico. One significant feature in this field is that flow takes place through isolated formation layers, and choices made regarding the seawater injection wells have a great impact, not only on the BaSO4 scaling tendency, but also on the placement of scale inhibitor squeeze treatments in the producers. In addition to seawater injection, oil production is supported by the aquifer. The first stage of this study involved identifying the split between connate, aquifer and sea water in the produced brine. This provided data that could be used to calculate the evolution of the scaling risk over the lifecycle of each well. The formation brines contain barium and the injection water is full sulphate seawater, and the relative proportion of each brine, the water production rate, and pressure and temperature conditions all determine the scaling risk. The evaluation of the extent of reactions between the injection water (sulphate) and formation water (barium) from injection to production well can result in a significant reduction in the available barium within the produced water, and hence the scale risk and scale inhibitor concentration required to prevent scale deposition. In this study, as the injection wells were completed with inflow control devices (ICD's) it gave the opportunity to manage the injection split via these ICD's, not only to improve sweep efficiency, but also to balance reservoir pressures and make squeeze treatments more efficient. The study will present the squeeze treatment volumes and estimated treatment lifetimes possible for two scenarios for the water injection application to this deepwater field. The implications of this type of study will be highlighted in terms of the options that this data allows an operator to consider prior to commissioning water injection in these challenging environments.
Rig Time Was Saved in a Remote Two -Rig Operation Completing Horizontal Openhole Wells with Expandable Sand Screen Through Careful Selection and Aggressive Juggling of Multiple Reservoir Drill-In Fluids
Authors: Luyster M. , Anez M. J. , Brzezinski M. A. , Nguyen C. , Ravitz R. , Bumala P. L.
Published: June 2014

A drilling and completion program was developed for a two-rig deepwater completion campaign in West Africa that included openhole water injectors and oil producers drilled in a highly unconsolidated sandstone reservoir with permeability that ranged from several Darcy to tens of Darcies. The limited storage onshore and discharge options mandated recycling fluids from well to well.

To minimize rig time on the two semi-submersibles, a plan was developed to juggle the five required fluid systems:

an oil-based drilling system for the uphole sections a reservoir drill-in fluid a screen-running fluid a breaker system a clear completion brine

Each system was designed and tested during the planning stage to meet project objectives. For the expanded sand screen application, the 8½-in. hole diameter could not be washed out more than 9¼ in. Wellbore stability required the drill-in fluid to be at least 10.8 lb/gal to control the shale and avoid hole eccentricity. Fluid rheology was critical as circulating density could not exceed 12.3 lb/gal to stay below the predicted 12.5-lb/gal fracture gradient, and good hole cleaning was essential in the horizontal sections that reached out to 1,000 m.

When running the screen, particulates in the mud had to pass through the 150-μm mesh otherwise the screen would plug and ultimately collapse. To attain the required weight, the screen-running fluid utilized fine micron-grind barite to attain density while avoiding screen plugging. Once the screen was in place and expanded, a delayed breaker was spotted in the screen to eventually dissolve the carbonate filtercake left behind by the drill-in fluid. The well was then displaced to completion brine. Reducing cross contamination during these displacements was important to avoid costly disposal.

The unique chemistry and properties of these systems demanded a comprehensive fluid management and quality control plan that began with product procurement, through the warehouse and mixing plant, onboard the supply vessels that stored these fluids, and final transfer and use on the rigs. Avoiding cross contamination and preservation of each of the different fluid for each successive well was crucial to minimize damage to the target sand, reduce rig time, and to reduce overall cost.
Development of a New Squeeze Scale Inhibitor for Mitigating Formation Damage for High TDS High Temperature Tight Carbonate Reservoir
Authors: Chen Tao , Lewis Jennifer , Chen Ping , Benvie Ronald , Hagen Thomas , Montgomerie Harry
Published: June 2014

The development of effective scale squeeze inhibitors in tight carbonate reservoirs with permeability less than 5md is still a big challenge, especially for high Total Dissolved Solids (TDS) and high temperature wells. The formation damage is one of the major considerations in high TDS, high temperature, and tight carbonate reservoirs as it can be caused due to fines mobilization, carbonate reservoir dissolution and collapse, and scale inhibitor compatibility issues. For the development of any scale inhibitor for squeeze application, the product must also demonstrate good inhibition performance, long squeeze life and accurate residual analysis at low concentrations.

This paper will demonstrate a logical design procedure to develop a new scale inhibitor suitable for a challenging high TDS, high temperature tight carbonate reservoir through squeeze application. The new scale inhibitor has been shown to be nondamaging to tight carbonate reservoir material under high temperature high TDS conditions, along with excellent retention and release characteristics. The results of a comprehensive testing program, including compatibility, formation dissolution, dynamic tubing blockage and core flood tests will be presented that will highlight the development of a non-formation damage scale inhibitor suitable for the high TDS high temperature tight carbonate reservoir.

In addition, the potential mechanisms of formation damage will be addressed. The impact of calcium tolerance, pH and molecular chemistry, carbonate reservoir dissolution and lab test procedure will be discussed compared to some traditional phosphonate and other polymeric scale inhibitors.
Advanced Understanding of Matrix Stimulation Treatments Through In-Job and Post-Job Evaluation of Real-Time Downhole Measurements with Coiled Tubing: A Case Study
Authors: Ahmed Danish , Ramondenc Pierre , Baez Fernando
Published: June 2014

Matrix stimulation treatments executed with coiled tubing (CT) face various challenges in terms of design, execution, and evaluation. The design phase typically relies on information that is frequently poorly known (e.g., extent of damage). Treatment pumping schedules and fluid concentrations are often determined based on previous experience and accepted local practices. For the execution to be completed within a safe framework, the standard is to keep pumping pressures below the fracturing pressure. In some cases, tools like high pressure differential jetting nozzles are used to provide deeper penetration and lower breakdown pressures. The depths at which those tools are operated usually depend on a prior log interpretation. Finally, treatment evaluation is typically limited to the comparison of pre and post-stimulation wellhead pressures and rates.

Over the past decade, numerical modeling has allowed the industry to address some of the design and evaluation challenges. Yet, the same question often remains: has the design been effectively executed and was the intervention successful? The answer depends on the choice of success criteria such as efficiency, safety, and economics.

CT enabled with fiber optic telemetry—which consists of downhole gauges providing real-time data of pressure, temperature, gamma ray, and casing collar locator—has proven a game-changing technology with respect to treatment execution, improving both intervention efficiency and safety (Jacobsen et al. 2010). The provided measurements, along with the possibility to acquire distributed temperature surveys (DTS), have also shown to be the most effective solution for treatment evaluation to date.

The case study presented here not only describes how CT with downhole sensors was used to optimize the acidizing treatment of an oil well producer and ensure its effective stimulation, but it also demonstrates how the real-time and DTS data were analyzed both during the intervention and through post-job numerical modeling, in order to refine the understanding of the well and that of its formation characteristics.
An Innovative Approach to Forecasting Matrix Stimulation Treatment Results: A Case Study
Authors: Ahmed D. , Haryanto E. , Soendoro F. H. , Baez F. , Bolanos N. , Zhou W.
Published: June 2014

Successful matrix stimulation engineering depends on knowledge of formation damage and its extent in causing the well not to produce to its potential. Stimulation design is a complex procedure as formation properties need to be honored when designing for sandstones, whereas for carbonates reservoirs, the presence of secondary porosity along with matrix requires a somewhat different approach. Operating companies have positive expectations for matrix treatments as they see it as a cost effective, efficient and safe approach of intervention to restore or stimulate production of a well that has formation damage.

In the oil and gas industry, diverse software applications are available to model matrix stimulation treatments but validity of such models depend on their robustness, starting with input data; i.e. formation characteristic such as permeability, porosity, pressures, temperature, skin-damage and its extent have strong impacts on the simulation results. Not very often is all of this information available; and if it exists, sometimes it's not up to date or questions may arise about the accuracy. This leads to operators to question how valid the design is and if it will allow them to meet their goals or not?

This paper describes an innovative approach that has been implemented to establish an effective stimulation design and forecast results based on execution parameters. The idea consists in using real-time downhole pressure and temperature measurements, along with Distributed Temperature Sensing (DTS) acquired during matrix stimulation execution. The downhole data is utilized to calibrate the formation and fluid characteristics via pressure matching which provides ability to determine how much of actual skin is reduced. This result is then incorporated to a reservoir model to forecast and evaluate the potential of the post stimulation production results.
Proppant Pack Permeability: Does it Matter? Field Case Histories of a Nearly Residue-Free Crosslinked Fluid System
Authors: Inyang Ubong , Fontenelle Lucas , Schultheiss Nate
Published: June 2014

Crosslinked polymer hydrogels are commonly used in hydraulic fracturing to provide enhanced fracture width and length, while providing the ability to suspend and transport high concentrations of proppant deep into the generated fractures. Then, during post-fracture cleanup, the gel viscosity must be reduced and the broken fluid flowed back through the proppant to the wellbore. This process should occur with minimal damage to the proppant pack so as not to restrict hydrocarbon production from the reservoir. Significant permeability damage to the proppant pack occurs if insoluble residue from the fluid becomes trapped within the pores of the proppant pack. Consequently, it is of prime importance to ensure the fluid breaks cleanly and any insoluble residue is minimized.

A new nearly residue-free (res-free) fracturing fluid was developed for use in crosslinked fluid applications. This fluid system was found to be very clean, leaving little to no residue (< 1%) upon breaking, leading to improvements in well cleanup and increased hydrocarbon production. This new fluid is a polysaccharide-based material that can be formulated to provide the necessary fluid performance parameters expected from traditional guar-based systems, but without the damaging insoluble characteristic of guar-based fluid systems.

A number of successful treatments using the res-free fluid have been performed, resulting in superior production. This paper describes the fluid system, laboratory testing and results, field operation best practices, and production data from a series of wells stimulated with the nearly res-free fluid compared to offset wells.
Successful Application of a Differentiated Chelant-Based Hydrofluoric Acid for the Removal of Aluminosilicates, Fines, and Scale in Offshore Reservoirs of the Gulf of Mexico
Authors: Sopngwi Jean-Jose S. , Gauthreaux Alex , Kiburz Daniel E. , Kashib Tarun , Reyes Enrique A. , Beuterbaugh Aaron , Smith Alyssa L. , Smith Steve K.
Published: June 2014

The Ewing Bank 873 (EW 873) Field is an offshore mature field in the Gulf of Mexico that produces hydrocarbon from Pliocene stacked turbidite sands. Wells in the EW 873 Field have experienced production impairment from formation damage, such as aluminosilicates, fines, and scale, including calcium carbonate (CaCO3) and barium sulfate (BaSO4). This paper discusses the results of the successful application of a differentiated chelant-based hydrofluoric (HF) acid to remove formation damage and enhance oil production (by as much as 305%) from Well A-04 in the EW 873 Field. Additionally, the paper presents the chemical analyses of the acid flowback as well as the methods used to characterize the formation damage. More importantly, the paper also focuses on the research efforts that led to the development and successful application of the differentiated chelant-based HF acid.

Throughout the research, analytical experiments and corefloods were performed with different acid formulations on cores that contained acid-sensitive clays, CaCO3 and BaSO4. Two formulations contained alpha-hydroxycarboxylic (a-HCA) HF acids, and other formulations contained chelants and chelant HF acids, which were both based on an aminopolycarboxylic acid (APCA). The APCA/HF acid proved to be the most effective formulation, as it achieved the highest permeability increase (relative to brine) and dissolved ions while mitigating precipitation. Furthermore, the APCA/HF acid is biodegradable, and compatibility and corrosion testing indicated that it is compatible with the produced oil samples of Well A-04 and it exhibits low corrosion loss (< 0.05 lbm/ft2) when applied with a chosen corrosion inhibitor on 13-Cr metallurgy, respectively.

The development of this differentiated APCA/HF acid highlights the potential of performing successful acid jobs where complex mineralogies, such as CaCO3 and BaSO4, are present.
An Innovative Approach for Sand Management with Downhole Validation
Authors: Subbiah Surej Kumar , de Groot Lex , Graven Hilbrand
Published: June 2014

Sand production caused the abandonment of two production wells out of four in a gas field located in the Netherlands sector of the North Sea. The forced two abandoned wells due severe sand production accounted for 75% of total gas production from the field. The loss production was unexpected. This paper describes how geomechanics was applied to develop a screenless completion design for one well, and cased-hole with gravel packs for three others, to re-establish economic sand-free production rates for the field.

A geomechanics study of the reservoir sections of the abandoned wells examined the mechanical properties, including rock strength and plasticity, as well as the state of stress acting on the producing sections. The study predicted the sanding history of both wells accurately. Modelling indicated that a thin sand layer with low rock strength was the main contributor to the overall sand production. This was later validated with a Downhole Sand Detector Tool. The modelling also indicated that sand production was likely from other, stronger sections of the reservoir as the field continued to deplete

Once a validated prediction of sand failure had been constructed for the reservoir, the study investigated improvements to the well design that would give both economic production rates and sand-free production for the lifetime of the field. In addition to considering geomechanical properties, the study investigated the geometry of the completion to find the most stable orientations for the wellbore and the perforations.

After an economic feasibility study, one of the abandoned wells was sidetracked along the optimally selected trajectory and perforated with oriented guns, isolating identified weak zones. The field has been producing since this remedial work without any sand production, and the missed production has been recovered. As the results, this meets the operator production and recovery objectives for the field.
A Comprehensive Approach to Estimate Invasion Radius of Mud Filtrate to Evaluate Formation Damage Caused by Overbalanced Drilling
Authors: Ling Kegang , Zhang He , Shen Zheng , Ghalambor Ali , Han Guoqing , He Jun , Pei Peng
Published: June 2014

Formation damage caused by overbalanced drilling (OBD) using water-based mud (WBM) is inevitable as a result of mud filtrate invading into the near wellbore formation. The invasion radius is critical to the multiphase flow when the well is put on production. It contributes to the total skin that hinders the hydrocarbon production. Furthermore, the response of the logging tools may be affected as a result of such invasion, rendering many inaccurate calculations of the formation evaluation. To evaluate the skin caused by mud filtrate invasion, it is imperative to determine the radius of invasion properly. A thoroughly literature review indicated that the previous investigations have focused on formation damage caused by drilling mud filtration, and none of them had proposed a practical, comprehensive, and reliable method, with solid theoretical base, to quantify this formation damage. This work filled this gap.

In this work, we developed a practical and comprehensive model to determine the depth of mud filtrate invasion near the wellbore. The distribution of mud filtrate saturation in the near-wellbore region is also calculated by employing drilling operation parameters, mud filtration test data, relative permeability, and drilling time. With the accurately determined invasion radius, skin factor can be evaluated confidently. Then the well stimulation can be planned accordingly and appropriately, if it is necessary to remove or alleviate formation damage. Therefore, this work is significant in skin calculation and well stimulation design. It can also be used to estimate the cleanup period at the beginning of production, and allows engineers to predict the well performance and diagnose wellbore problems by checking any deviation from the predicted production. This study can also assist with the correction of parameters inferred from log measurements, thereby reducing the over and/or underestimation of log derived parameters used in various formation evaluation calculations.
Practical Laboratory Testing for Shale Fracturing
Authors: Fischer C. C. , Constien V. G.
Published: June 2014

A suite of practical laboratory tests has been developed to characterize the performance of shale fracturing fluids and chemicals. The testing suite includes friction reduction, capillary suction time, and shale strength changes after exposure to the fracturing fluid.

The friction testing method was correlated to previously published work in larger diameter tubing and utilizes a small volume of water so that actual field water samples can be used. The capillary suction utilizes off-the-shelf equipment to give rapid determination of fluid and shale interactions. The shale strength change method involves dynamic exposure of shale cores to the fracturing fluid at temperature, shear rates and times representative of the fracturing treatment. Shale strength changes are determined by measuring hardness of the core surface exposed to the fracturing fluid and comparing it to the opposite side of the core which was not exposed to fluids.

The friction reduction test has been used with great success to rate the performance of friction reducers in various types of water, to determine optimum friction reducer concentration, and to determine the interaction of other common additives such as biocides or scale inhibitors with the friction reducers. The strength testing has shown significant strength reduction in some shales with certain types of fracturing fluids and little strength reduction when the fracturing fluid was changed. A variety of fracturing fluids have been tested from slickwater to gelled oil fluids to traditional crosslinked fluid. The strength reduction should be indicative of proppant embedment in the shale.

The suite of tests proposed has been successfully used for multiple operators in order to determine interaction effects of fracturing fluids with shales as well as to optimize friction reducer performance.