bluuebunny/crossref_metadata_2025_split huggingface dataset:
Low-Solids-Shear Dependent Cement System Eliminates Loss Circulation in the Upper Spraberry Formation in the Permian Basin: A Case History
Authors: Duffy Marcus , Hernández Olvin , Rojo Gustavo 
Published: March 2017

Abstract
Lost circulation is a recurring challenge and high-cost event within the oil industry, particularly in depleted or weak fracture-gradient zones. Lost circulation can significantly increase operational costs, nonproductive time (NPT), the possibility of stuck pipe, and, in some cases, can result in well loss.
Lost circulation can be defined in a variety of ways, ranging from partial to total losses in a variety of formations, including highly permeable, fractured, or cavernous formations. In cases of total losses, conventional lost circulation material (LCM), such as gel-based and large-particulate-laden fluid, can be ineffective when it is unable to isolate the flow zones.
The fluid system discussed in this paper uses a low-solids shear dependent cement (LSSDC) system that will remain fluid until the system begins to lose shear rate to remediate loss circulation. As the fluid system enters the loss zones and the shear rate is reduced, rapid gel strength development occurs. The cement system will become pumpable again, for a few cycles, if shear is reapplied within a specified time frame. After the shear rate has been sufficiently reduced to enable the gel strength to develop, rapid compressive strength development ensues. This development enables the isolation of cavernous or vugular formations that could have partial or total losses. The rapid compressive strength development enables drilling to proceed within a relatively short amount of time as the hydrated cement is capable of withstanding circulation pressure.
Drilling through the Upper Spraberry formation, located between 6,500 and 8,500 ft in the Permian basin, represents a drilling challenge because of lost circulation difficulties. Traditional treatments to reduce the lost circulation issues include cement plug operations and mud sweeps with LCM, but none have established a consistent lost circulation resolution. For this case, the producing company prepared 100 bbl of mud sweep containing fibers, mica, and nut fines as LCM. However, total losses continued with no improvement as the LCM sweep was pumped. A total of 42 bbl of the LSSDC was then pumped; operations proceeded successfully, and the well was drilled with no other lost circulation problems. The fluid system presented remediates lost circulation through a mechanism that, unlike any fluid system within the oil industry, develops rapid compressive strengths after it is placed to withstand circulation pressures and to enable drilling to continue.
Experimental Study and Pilot Test of Combined Gel Treatment and Surfactant Imbibition Technology in High Temperature, High Salinity Reservoir
Authors: Hongyan Cai , Wenli Luo , Desheng Ma , Xinyu Zhou , Jian Fan , Jianguo Li , Jianfeng Sun , Yi Zhang 
Published: March 2017

Abstract
With the depletion of petroleum resources, EOR in marginal oilfields attracts more and more concern worldwide. For high temperature, high salinity (HTHS) reservoirs, CEOR shows promising potential while faces great challenge due to adverse effects on chemicals by severe reservoir conditions. Curling, thermal degradation, and breakdown of molecular segment caused by HTHS makes polymer an unsatisfactory candidate. How to effectively improve mobility control and achieve high recovery becomes one of the key issues in CEOR of HTHS reservoirs. Herein, a CEOR method combining gel treatment and surfactant imbibition was put forward and evaluated for a HTHS reservoir with reservoir temperature 126 °C, injection brine salinity 117,000 mg/L, and divalent ion content 3,340 mg/L. Gel formulation was optimized to suit application requirement. Tests on solubility, thermal stability at HTHS conditions, and spontaneous imbibition were performed for several surfactants to obtain suitable chemical agent for target reservoir. An organic crosslinker was added to the diluted solution of a heat tolerant, salt resistant Star-shape polymer to form flowing gel. Evaluation results showed the viscosity of gel reached 43,900 mPa·s at 5th day and standed at 43,500 mPa·s after 180 day aging, demonstrating good thermal stability. An anion-nonionic surfactant showed good compatibility with brine, acceptable thermal stability at HTHS, and sound spontaneous imbibition recovery. One injector three producer pilot test was conducted employing the gel plus surfactant formulation and an incremental oil production of 3660 MT was accomplished. In-lab evaluation and pilot test displayed inspiring result of gel with surfactant imbibition technology, which provides a good option for CEOR of HTHS reservoirs.
Innovating in the Oil and Gas Industry: A Framework for Aligning Innovation Strategy and Tactics
Authors: Redden James E. , Strickland Cary T. 
Published: March 2017

Abstract
The decline in oil prices in 2015 and 2016 has forced innovation managers within the oil and gas industry to do more with smaller budgets. To meet this challenge, oil and gas companies in the United States need to optimize their innovation investment. By interviewing experts across the industry, we have identified six common innovation behaviors. Explicitly aligning these behaviors with innovation strategy can help oil and gas companies spend limited innovation dollars wisely. To help guide decision making, we developed three innovation archetypes (reactive, opportunistic, and proactive) that describe the relative emphasis that various companies place on different innovation behaviors. Reactive innovators limit their investment in innovation activities but forgo some of the competitive advantage offered by new technology. Opportunistic innovators keep pace with new technology but have relatively little control over developing innovations. Proactive innovators help shape technology development to derive maximum value from the innovations developed. Innovation managers can use the framework in this paper to assess their portfolio of activities holistically, or they can apply these archetypes to specific technology domains (e.g., big data or oilfield chemicals). This new framework can help align tactics with strategy to maximize innovation outcomes while oil prices remain low.
Interrelating Production Analysis with Pore Scale Structure in the Bakken Reservoir
Authors: Grella M. A. , Callard J. 
Published: March 2017

Abstract
Conventional laboratory methods for obtaining relative permeability in oil and gas shales are difficult if even possible to obtain. Insight can be gained from high pressure mercury injection and the relative permeability obtained there from using pore throat models. An integrated approach between relative permeability derived from core laboratory pore throat models with production analysis allowed us to generate new type curves that can be used with field production to determine Brooks Corey wetting phase exponents.
A procedure utilizing laboratory mercury injection capillary pressure on core samples from the Bakken reservoir is used to generate a distribution of wetting phase saturation exponents and residual wetting phase saturations for numerical simulation model input. Model output is normalized by the time and cumulative oil production at the onset of boundary dominated flow to generate type curves that can be used to successfully history match field production in the Bakken formation in North Dakota.
A new type curve has been developed in which oil production and transition from linear to boundary dominated flow are the two requirements needed to derive oil-gas relative permeability. The median of wetting phase saturation exponents for the Middle Bakken formation ranges between values of 2.3-2.6.
Other useful results from the combination numerical simulation and field production data study include the prediction and observation of an elevated yet constant producing gas oil ratio during the linear flow period (prior to boundary dominated flow.) Several consequences of this result allows selection of proper application of decline curve analysis techniques, properly determine initial solution gas oil ratio for fluid characterization, and indication of relative permeability prior to the onset of boundary dominated data.
Prediction Model for Gas Migration in Well During PMCD Operation
Authors: Terra Felipe de , Lage Antonio Carlos , Fjelde Kjell Kåre , Naccache Mônica Feijó , Stuckenbruck Sidney 
Published: March 2017

Abstract
The use of the Managed Pressure Drilling (MPD) is spreading in offshore operations. The increasing complexity in the new exploratory frontiers is demanding for new techniques to reduce costs and increase operational safety. MPD appears as an answer for that demand and sometimes it is the only viable way to drill some of the challenging wells. In that way, understanding the gas migration behavior while drilling in PMCD mode allows an optimized well design concerning cost and operational safety.
The present study validates a mathematical model capable of simulating a scenario where loss of drilling fluid in the bottom of the well is present while having an influx from the same reservoir and observing gas migration to the surface in a PMCD operation. A Drift Flux Two Phase Flow Model is used in association with the Advection Upstream Splitting Method (AUSMV). Before the presentation and discussion of the complete PMCD scenario, two simple cases were simulated and the results were compared to the ones from a computer application considered as a reference to the industry, validating the proposed model. The results of the simulations can be used as a base for the elaboration of operational procedures to monitor gas behavior and optimize bullhead in PMCD scenarios.
Lessons Learned in Drilling Fluids Projects during MPD and MCD Operations in Brazil's Offshore Wells
Authors: Teixeira G. T. , Fabri F. , de Almeida L. S. , da Silva P. H. , Vadinal R. B. 
Published: March 2017

Abstract
Drilling fluids play great importance to the success of MPD (Managed Pressure Drilling) and MCD (Mud Cap Drilling) operations. On MPD projects, the correct design of the drilling fluids properties, such as, density, rheology, anchor point position and compatibility should be precisely adjusted in order to operate in good and safe performance, especially in a statically underbalance MPD projects. Exceptional importance should be addressed to the initial mud density to provide useful capacity to carry out a Dynamic Porous Pressure Test (DPPT).
MCD operations require a suitable drilling fluid project due gas migrations, costs and cuttings transportation issues, related to LAM (light annular mud) and sacrificial (SAC) fluids.
The objective of this paper is to present the lessons learned in drilling fluid projects during MPD and MCD operations in Brazil's offshore wells. The study will focus on desired properties, simulations, adjusted hydraulics models, formulations and involved costs, considering water and olefin based drilling fluids.
Overview of Different Applications for MPD and MCD Techniques on Deepwater Wells
Authors: Fernandes André Alonso , Tomita Reinaldo Akio , Junior Antonio Carlos , Abdu João Paulo , Vanni Guilherme Siqueira , Grandi Ricardo Freire , Longo Fabio Leonardo , Machado Giovani Ferreira , Agostini Cristiano Eduardo , Vadinal Rodolfo Balthazar , Silva Luiz Felipe 
Published: March 2017

Abstract
MPD is a very powerful tool that is gaining momentum for deepwater offshore wells construction. A dynamic positioning rig adapted to MPD operations can apply different techniques that better suit to each well scenario. Currently Petrobras has over 20 MPD deepwater offshore wells drilled, having applied different techniques to achieve success: from "basic" SBP to MCD variants. This paper discusses the various MPD techniques that can be utilized from a dynamic position rig during deepwater well construction.
Managed Pressure Drilling Flexible Mud Return Line Advances
Authors: Szekely Gergely , Peixoto Eduardo , Czovek Zuzana , Mezo Tamas 
Published: March 2017

Abstract
In the oil and gas industry there is a common misconception that bonded flexible pipes designed according to the only approved standard for deepwater MPD applications, API 17K are overdesigned and heavy.
This paper is to clarify the misconception and present to the industry the flexibility that API 17K gives to tailor the hose construction reflecting the actual requirements and customer needs. Over the last few years a lot has been learned on the MPD operations, using inputs of the industry's major players, the hose requirements that in the past led to overdesigned, heavy and expensive flexibles have been revised, allowing a more efficient hose construction to be developed keeping the design premises of API 17K. This newly developed MPD mud return line construction assures a significantly lighter and easier to handle hose while not compromising on HSE and quality.
Brief overview on API specifications is given in terms of their applicability to MPD operations. Technical challenges and solutions are discussed in details for the flexible pipes carrying well effluents in kick situations with special emphasis on technological advances resulting meaningful weight and cost savings. Results of the full scale tests demonstrating the hose performance are presented, such as bending stiffness test, blistering test and burst test.
Strategic Evaluation of MPD Application on DP Rigs
Authors: Aranha Pedro Esteves , Fernandes André Alonso , Vanni Guilherme Siqueira , Terra Felipe de , Tomita Reinaldo Akio , Tolfo Marcos Coradini , Gozzi Danilo Signorini 
Published: March 2017

Abstract
In recent years, PETROBRAS has been using MPD (SBP/MCD) technology in ultradeepwater scenarios at development and exploratory wells. Although MPD techniques are an advance over conventional drilling, it also brings more complexity to the operation and, in some cases, increases the duration and costs of the interventions when compared to conventional drilling.
Ideally, the rigs equipped with MPD system should only be used in wells, or in specific phases of the well, that requires MPD to conclude or where the NPT associated with fluid losses is considerable. In these scenarios, the extra costs and extra time necessary are negligible, compared to the NPT avoided, and the alternative would be not to reach target depth or drill the well.
Geomechanics, pore pressure estimation and loss zone identification are not an exact science. There is always an uncertainty in predicting MPD (SBP/MCD) demand, pushing the development of techniques and strategies to optimize the allocation of MPD rigs in wells where the NPT would be so high that the use of the MPD is advantageous, or, where MPD is an enabler of well construction.
This paper describes a probabilistic analysis developed to support the determination of MPD (SBP/MCD) demand, calculating the optimum number of rigs to be equipped with MPD (SBP/MCD) and RCD system, and which intervention strategy is the most cost effective for a development campaign, based on historic results.
Lessons Learned from MPD Operations with Underbalanced Drilling Fluid on Two Challenging HTHP Exploration Wells
Authors: Fredriksen Ragnar Marcelius , Bjerkås Johnny 
Published: March 2017

Abstract
The 2/4-22 S Romeo and the 2/4-23 S Julius exploration wells were drilled on the Norwegian continental shelf in 2014-2015, with a jack-up rig, utilizing Managed Pressure Drilling (MPD) and a hydrostatically underbalanced mud column. Both were High Pressure High Temperature (HPHT) wells with an expected Total Depth (TD) of 5500 m true vertical depth (TVD), expected reservoir pressures up to 2.14 SG and expected temperatures of 185 °C.
The 2/4 block is known for its challenging pressure and temperature regimes, and the underground blowout that occurred on the 2/4-14 well in 1989. The 2/4-21 King Lear well was drilled on the same structure as the 2/4-14 in 2012. Wellbore breathing, in combination with having a smaller drilling window than prognosed, caused drilling difficulties and endangered the likelihood of reaching TD and achieving the objectives of the well. For the two next well in the area, it was decided to utilize MPD to mitigate the expected drilling issues.
Both the 2/4-22 S Romeo and the 2/4-23 S Julius well encountered challenging drilling conditions that caused narrow drilling windows and the MPD technology was key for achieving the objectives for both wells. However, a serious well control incident occurred drilling the second well, when several barriers failed, following a sensor failure on the MPD equipment.
The purpose of the paper is to describe how the MPD operations were planned and executed, with focus on lessons learned.
A Mid-Riser Pump System Optimized for Rapid Deployment on Any Semisubmersible or Drillship
Authors: Piccolo Brian , Johnson Austin , Macgregor Alex , Pinkstone Henry , Leuchtenberg Christian , Fraczek Justin , Anderson Bo 
Published: March 2017

Abstract
The AFGlobal Corporation has developed a mid-riser pump system targeted toward managed pressure drilling (MPD) wells that maintains a full riser fluid column and statically overbalanced well at all times while excluding the need for rig and riser modifications or multiple interconnected manifolds at topside. The optimized configuration of this system is envisioned to permit rapid deployment on any deepwater floating drilling vessel to serve as one method of controlling equivalent circulating density. Ultimately, the PRS will serve as a stepping stone to full dual gradient drilling.
Wellbore pressure is controlled by utilizing a subsea pump system to reduce the amount of riser annulus pressure exerted on the formation. The subsea pump system is operated in conjunction with an MPD wellbore seal permitting a configuration where the pump system can take suction from the riser below the MPD wellbore seal and discharge back into the riser above the MPD wellbore seal. As such, all riser flow is returned to the rig via the main flow line which also permits the option for conventional or advanced kick detection techniques. Since there is no independent mud return line out of the riser, the riser is always full of drilling mud. The topside footprint consists of a combined hydraulic power unit and pump controller skid and umbilical reel permitting 1-2 weeks of rig up time. The pump system and MPD wellbore seal are packaged as single unit which can be deployed through the rotary table in the same manner as a conventional joint of riser. By utilizing a positive displacement pump, the power requirement is low enough for installation across a broad range of drilling vessels.
Managed Pressure Drilling Application in Severely Depleted Reservoirs Enables Successful Brownfield Drilling Campaign
Authors: Beutler Amber , Coffey Scott 
Published: March 2017

Abstract
A re-entry drilling campaign of six highly deviated wells was successfully drilled from a fixed offshore platform through depleted reservoirs by utilizing managed pressure drilling in eight hole sections. The main challenge was the narrow drilling window of 0.05 to 0.60 ppg between wellbore stability mud weight, driven by unstable shales, and reduced fracture gradient of the reservoir sands, driven by depleted pore pressure. The necessity to balance risk of lost circulation, hole cleaning, and wellbore stability drove the team to employ new technology in order to achieve success.
Managed Pressure Drilling (MPD) is one of several technologies for optimizing drilling operations and reducing Non-Productive Time (NPT) while drilling narrow windows. The Surface Back Pressure (SBP) variant of MPD can be used not only on exploration wells with pore pressure uncertainties to identify and control influxes, but also can be employed in severely depleted reservoirs to enable drilling operations which are conventionally unattainable due to constricting drilling window.
This case study discusses the main objectives and requirements for MPD, along with the planning, equipment, and execution strategies used to drill and make connections with a mud weight statically underbalanced to wellbore stability gradient. Furthermore, the paper discusses the use of novel pressure testing techniques and automated fluid displacements with the MPD system to maintain a constant anchor point pressure prior to tripping and avoid losses and wellbore collapse. Finally, this study provides results, achievements, and recommendations on SBP application in a brownfield reservoir.
Planning of an MPD and Controlled Mud Cap Drilling CMCD Operation in the Barents Sea Using the CML Technology
Authors: Bysveen Johan , Fossli Børre , Stenshorne Per Christian , Skärgård Gustav , Hollman Landon 
Published: March 2017

Abstract
The subsurface formations and reservoir conditions encountered in certain areas of the Barents Sea offer some unique challenges for the operators and the drilling industry. These areas of the Norwegian Barents Sea consist of naturally fractured and weathered carbonate formations which may incorporate open karsts. Drilling into large open fractures or karsts will result in total losses and mud cap drilling practices must be employed to enable further progress. Such locations may require some unique solutions to drill effectively and safely while conforming to local rules and regulations; including deploying winterized rigs capable of year-round operations in Arctic environment.
This paper describes the process of selecting a viable solution for drilling in such an area where potential mud cap drilling practices could be required, the rig integration process, class notation process, development of operational procedures, risk assessment, training and testing of equipment prior to commencing the operation.
This was a fast track project which incorporated developing new mud cap drilling procedures and processes when operating the Controlled Mud Level (CML) system. Since mud cap drilling practices from a floater on the Norwegian Continental Shelf (NCS) is a rare occurrence, it required close cooperation between the operator, the drilling contractor and the service provider. To facilitate the process and assure sound practices a third party with experience on mud cap operations was also engaged. The paper will also briefly describe the Controlled Mud Cap Drilling (CMCD) principle and the results from drilling the well.
An Experimental Study on Riser Gas Behavior for Dual Gradient Drilling
Authors: Kaldirim Omer , Schubert Jerome J. 
Published: March 2017

Abstract
Offshore well costs and risks have proven the need for research in deep water drilling and well control. This paper presents the experimental research that is ongoing at the Dual Gradient Drilling Laboratory to understand the physics involved in gas migration.
A scaled prototype of an offshore well was built to mimic the Controlled Mud Level (CML) Drilling method. Instrumentation and cameras were used to monitor flow rate and gas liquid ratio. Set rates for the mud outflow and inflow were determined and tested at constant gas influx, by increasing the mud inflow in narrow increments.
The prototype was successfully tested and removed a large amount of gas from the system before the gas migrated into the voided section. The results of these tests show that using high mud inflow rates can eliminate the single bubble system, leading to a dispersed bubble system. With dispersed gas bubbles the removal of the gas is a process of determining an optimal outflow rate that would also accommodate the fluid level requirement. Also, it was observed that the geometry of the outflow line have a major effect on the gas flow behavior. With the reduced outlet diameter, a Bernoulli flow was observed which increased bubble dispersion.
This paper provides information regarding the research on gas behavior and migration in a scaled riser system during circulation. These experiments can be used to study the effects of flow rates on gas dispersion and elimination from the CML Drilling method.