bluuebunny/crossref_metadata_2025_split huggingface dataset:
Plugging Testing Confirms the Reliability of the Fluidic Diode-Type Autonomous Inflow Control Device
Authors: Greci Stephen , Least Brandon , Aitken Liam , Ufford Adam 
Published: September 2014

Abstract
Because of their capability to delay water and gas breakthrough in horizontal completions, inflow control devices (ICDs) are being used widely in completion strategies to delay water and gas breakthrough. These devices add an additional pressure drop to the production fluid, and this additional pressure drop helps to balance the heel-to-toe effect in long homogenous horizontal completions. ICDs can perform a similar function in heterogeneous wells by configuring the ICDs to have an increased pressure drop in the more permeable zones. With the oil influx more evenly balanced, total oil recovery is maximized.
The next generation ICD is an autonomous inflow control device (AICD), which will independently create a greater pressure restriction against the breakthrough of unwanted fluids. AICDs, as well as ICDs, have relatively small fluid passageways required to help create their fluid restriction. A common concern among operators when running a device with a restricted fluid-flow passage, however, is the risk of plugging by drilling mud, produced fines, or any other debris that travels through the device. To eliminate the concern over plugging the AICD, a test procedure was drafted, and a test program was run to mimic the worst-case scenario down hole.
This paper will focus on the procedure, testing, and results of a plugging test developed for the fluidic diode-type AICD. Oil was used to obtain base line performance curves through the AICD. Drilling mud was then circulated through the AICD at various flow rates over an extended period of time. Finally, another oil performance curve was generated to compare against the original oil-flow curve. During flow tests, the plots were analyzed to ensure that there were no indications of plugging in the device. Since no potential plugging conditions were found, the testing verified that the AICD passed the plugging test. After running a test such as this, operators now can feel more confident that the AICD will not sustain any plugging issues down hole in similar conditions.
Use of Liner Drilling Technology to Isolate a Depleted Sand - A Case Study in Mississippi Canyon
Authors: Rosenberg Steven M. , Karimi Moji , Manuel Blake , Tan Ming Zo , Salinas Alexandro , Winchell Rex L. 
Published: September 2014

Abstract
This paper will illustrate the collaborative approach an international oilfield services company and Gulf of Mexico operator used for the planning and successful execution of a 9-7/8-in. x 14-in. Drilling with Liner (DwL) operation to isolate a 6.5 ppg depleted sand interval and mitigate expected losses in a deep water block of Mississippi Canyon. Conventional methods would have most likely have required an 11-3/4-in. or 11-7/8-in. contingency liner for the operator to meet their well construction objectives. Early collaboration between the service company and operator identified DwL technology as the core technology to meet the operator's well construction objectives. The DwL process allows a hazard interval to be isolated in a single trip resulting in less risk and exposure compared to the use of conventional drilling methods. Since DwL technology encompasses a multitude of engineering disciplines, these were integrated into the drilling plan in a seamless manner, ensuring the DwL objectives would be met. To accomplish this, the service company formed a dedicated well engineering team which collaborated with the operator early on in their well planning process.
The engineering disciplines with associated modeling during the DwL planning phase provided technical assurance the 9-7/8″ liner string could be drilled to a satisfactory setting depth while also providing a high-integrity wellbore to the operator over the entire life of the well. These disciplines included:
Torque, drag and hydraulics modeling of the liner running and drilling operation, Connection cyclic fatigue analysis, BHA and directional tendency modeling Cementation and centralization Formation drillability analysis Plastering effect evaluation
During the planning phase, regular operator-service company communications along with project scheduling software gave the operator assurance that agreed upon deliverables would be completed in the allotted time frame with the intended well objectives met.
The 9-7/8-in. x 14-in. liner successfully drilled through the depleted sand reaching a competent setting point, eliminating a potential contingency liner. This paper will present the DwL planning process, associated risk assessment modeling to ensure that safety, environmental and DwL objectives were met, and the DwL operation with its successful outcome
Completion Deployed Scale Inhibition Applications in Deep-Water, West Africa
Authors: Jordan Myles M. 
Published: September 2014

AbstractThe injection of seawater into oil-bearing reservoirs in order to maintain reservoir pressure and improve secondary recovery is a well-established, mature operation. Moreover, the degree of risk posed by deposition of mineral scales (carbonate/sulphate) to the injection and production wells during such operations has been much studied. The current deep-water subsea developments offshore West Africa and Brazil have brought into sharp focus the need to manage scale in an effective way.In a Deepwater West African field the relatively small number of high-cost, highly productive wells, coupled with a high barium sulphate scaling tendency upon breakthrough of injection seawater meant not only was effective scale management critical to achieve high hydrocarbon recovery, but even wells at low water cuts have proven to be at sufficient risk to require early squeeze application.To provide effective scale control in these wells at low water cuts, phosphonate-based inhibitors were applied as part of the acid perforation wash and overflush stages prior to frac packing operations. The deployment of this inhibitor proved effective in controlling barium sulphate scale formation during initial water production eliminating the need to scale squeeze the wells at low water cuts (&lt;10% BS&W). To increase the volumes of scale inhibitor being deployed in the pre-production treatments and so extend the treatment lifetimes scale inhibitor was also added to the frac gel used to carry the frac sand.This paper outlines the factors that influence the suitability of pre-production treatments and present field data from treatments applied via stimulation acid, solid scale inhibitor in frac pack and scale inhibitor within fracture gel to illustrate these different methods and highlight the advantages and disadvantages of each approach.Many similar fields to the case study outlined in this publication are currently being developed in the Campos basin, Gulf of Mexico, and West Africa, and this paper is a good example of best-practice sharing from another oil basin.
Field-Detectable Scale Inhibitor for Severe Oilfield Environments
Authors: Schilter Randi D. , Yang Chao , Hill Matthew E. , Watson W. Philip , Ewan Kimberley Mac , Almond Stephen W. 
Published: September 2014

Abstract
The formation of sulfate and carbonate salts of barium and calcium during oil production and stimulation operations can result in blocked pore throats in the near wellbore region, narrowed production tubing, deposits on equipment, and in more serious cases, formation damage. Polymeric scale inhibitors are commonly used to prevent or slow this process, but one limitation of scale inhibitors is that they must be used at or above the polymer's minimum inhibitor concentration (MIC). Laboratory methods for determining the MIC are well known; however, determining when the scale inhibitor has been depleted below the MIC can prove challenging. One way to combat this is to continuously treat a producing well, but this results in additional chemical consumption and higher operating costs.
Polymeric scale inhibitors have been developed that contain detectable tags, allowing the residual polymer concentration to be monitored and reducing the chance of an underdose or overdose. This approach could potentially reduce operating costs; however, sophisticated and time-consuming offsite laboratory analyses, such as ICP or other spectroscopy methods, are required to detect the tags – time during which flow assurance can be compromised.
This paper reports an alternative tagged polymeric scale inhibitor that is easily detected by a simple in-field titration and provides outstanding carbonate and sulfate inhibition within favorable cost constraints. Additionally, the new novel tagged scale inhibitor is anticipated to be more environmentally friendly than phosphate-based scale inhibitors, a growing demand in the oil and gas industry. Analyses such as static jar tests and dynamic scale loop (DSL) testing were used to evaluate the scale inhibition efficiency. The performance of the new scale inhibitor versus commercially available scale inhibitor (SI) was highlighted by the DSL, where the MIC was determined to be 20 ppm versus 80 ppm for two widely used scale inhibitors in a barium sulfate scaling brine. The dual benefits of in-field detection and excellent scale inhibition make this alternative tagged scale inhibitor a promising and cost effective addition to the oil and gas industry.
Assessment of Foamed Cement Used in Deep Offshore Wells
Authors: Kutchko Barbara , Crandall Dustin , Moore Johanthan , Gill Magdalena , Haljasmaa Igor , Spaulding Richard , Harbert William , Benge Glen , DeBruijn Gunnar , Shine Joe 
Published: September 2014

Abstract
The use of foamed cement systems for deepwater applications has been increasing and is often the system of choice for shallow hazard mitigation as in the Gulf of Mexico. However, there is little information regarding foamed cement behavior under wellbore conditions. Research is being conducted to develop a predictive relationship between the mesostructure and physical properties of foamed cements used in offshore applications. Samples of foamed cement have been generated using both atmospheric laboratory and high-pressure field preparation methods. Field-generated foamed cement samples were collected in constant pressure (CP) sample cylinders using the same full-scale field equipment used to generate foamed cements in a well. These samples were scanned while inside the CP cylinders using X-ray Computed Tomography with a scan resolution of approximately 35 μm.
Results of the laboratory testing indicate a correlation between foam quality, bubble size distribution and physical properties such as strength and permeability. Initial results also highlight key differences in laboratory and field-generated foamed cements. The variations in cement structure within the field-generated foamed cement samples appear to indicate a strong relationship between the flow of the cement into the sample vessel and the final porosity and properties of the in-place hardened cement. This research will provide a better understanding of the effects that foam cement production, transport downhole, and delivery to the wellbore annulus has on the overall sealing process.
Paper Title: Ultra-High Pressure Perforating System Development
Authors: McClean Charlie , Myers Bill , Talapatra Didhiti 
Published: September 2014

AbstractA major oil field operator in the Gulf of Mexico had a well that was posing significant challenges to their perforating strategy, due to the extreme pressures that were expected. The operator required a perforating system that would survive in an environment with pressures as high as to 35,000psi.Technology that would enable any perforating system to withstand these extreme pressures had not been refined within the industry at the time of the customer inquiry, due to the limited number of projects with such extreme conditions. Therefore, a service company committed resources to develop and ultimately refine this product and identify the best system for the customer to achieve the optimum operational results with no lost or non-productive time from this service. The service company carried out detailed pre-design modeling to identify any concerns that would aid in tailoring the complete system.This paper reviews the development of this perforating system and identifies concerns that were encountered during the design and manufacture of the system. In addition, this paper describes the value that was brought to the project through the use of a detailed, customer-supported quality plan. The importance of correlation between real-life testing and modeling results in delivering a streamlined and fit-for-purpose system is also discussed.In summary, the paper describes and quantifies the inherent risks associated with perforating projects in extreme high-pressure environments. Moreover, this paper demonstrates how the service company responded to these risks in the design process to improve the system. Lessons learned are also discussed, along with information on service quality delivery.
Expanding Cement for Improved Wellbore Sealing: Prestress Development, Physical Properties, and Logging Response
Authors: Thomas Jeffrey , Musso Simone , Catheline Sebastien , Chougnet-Sirapian Alice , Allouche Mickael 
Published: September 2014

Abstract
Expansion of oilwell cement after placement in the annulus is a promising route to improve wellbore sealing. Expansion can potentially provide benefits such as: closing a microannulus, reducing the tendency for cracking/debonding, and improving cement logging evaluation. To properly evaluate the performance of expanding cement formulations in a laboratory setting, the cement should be hydrated under confined conditions similar to a wellbore. We conducted measurements using a new confinement cell developed in our laboratory. The cell provides radial confinement and elevated temperature as in a wellbore. The availability of water to the cement can also be controlled to simulate tight or porous formations. In the axial direction the cement sample contacts a piston that either confines the sample while measuring the axial stress development, or permits linear expansion that is measured. Using blends of oilwell cement with magnesium oxide (MgO), a standard expanding additive, we measured the axial stress development and linear expansion under different curing conditions. To better understand and optimize cement expansion we also characterized the hydration kinetics of the MgO additive alone and in the presence of the cement, using isothermal calorimetry. Finally, we measured the acoustic response of cement formulations with and without a commercial expanding agent with a standard ultrasonic pulseecho technique. This testing confirmed the benefits of expansion for the logging response.
Innovative Heavy Landing System for Ultradeep Offshore: Extended Slip Crush Resistant Tube, Enhanced Slip Design and Heavy Weight Carrier
Authors: Flores Vincent , Franchi Jonathan , Granger Scott , Vierke Andre 
Published: September 2014

Abstract
The offshore industry's current trend is driving towards ultra deepwater wells, combined with deeper total depths. In order to be able to set and run larger and heavier casing strings with hook loads approaching or exceeding 2.5 million lbs, an innovative heavy duty landing system has been developed and put on the market.
Such systems must be capable of landing heavy loads while ensuring slip crush resistance. It includes an extended slip with enhanced design (coupled with a new greasing system), a 2.5 million lbs landing carrier and a pipe with a thick walled high strength material section, a light weight tube, and a rotary shouldered connection.
One of the current operational challenges with existing heavy duty landing strings is linked to the positioning of the slips, in particular when using extended slip designs. The limited length of the slips area requires additional time for proper positioning and set up. To address these issues, a new slip proof section design has been developed: the combination of an extended crush proof section and the absence of a heat affected zone in that particular area decreases running time while completely eliminating the risk of setting the slips on a weak point.
The "Spiri-Reinhold pipe crushing" formula has been used to design this system. However, considering the approximation of this model's results, crushing performance has been assessed using the Finite Element Analysis, as well as physical tests performed with a specifically designed pulling unit. These full scale test results have been compared to the ones obtained with both the Finite Element Analysis and the standard "Spiri-Reinhold pipe crushing" formula.
Drill Pipe Riser Intervention System Successful Experience in Offshore West Africa
Authors: de Fonvielle Henri , Bordet Laurent , Campbell William , Susak Nenad , Marajh Mitra 
Published: September 2014

Abstract
While offshore intervention on subsea equipment is quite common, the increasingly deeper water operations require light weight intervention systems while meeting safe and stringent operating specification. For these new deep offshore challenges, the conventional risers are becoming a more costly and less desirable solution.
Starting with a recollection of the main drivers that motivated the development of drill pipe riser intervention systems (DPRISi), the paper details the technical and economical challenges in West Africa that have led to the design of such a solution. When non-productive time and financial aspects are taken into account, it makes sense to develop a dedicated system in order to provide fast and reliable intervention.
Depending on the field requirements, two different types of drill pipe riser systems using a proprietary double shoulder connection were used by operators. A first solution was developed in 1999 featuring a seal ring close to the external shoulder. Subsequently, a new solution featuring a gas-tight metal to metal seal on the pin nose was developed in order to address increasingly demanding and challenging operations.
Intensively used in West Africa since 1999, the solution using the seal ring has shown robustness and reliability while being used for several projects in Angola such as Girassol and Rosa and now GirRI. The paper draws a summary of these operations and the feedback on the field use and maintenance. Also it emphasises the successful qualification process for the metal to metal seal solution that has been used in offshore Nigeria since 2010 for the USAN project.
Case History of Laboratory Design and Field Application of Bio-Polymer Free Fluids for an Open Hole Gravel Pack
Authors: Allogo C. M , Luyster M.. , Nguyen C.. , Ravitz R.. , Perardel A.. 
Published: September 2014

Abstract
An operator and its partners operating in the Gulf of Guinea decided to drill and complete a horizontal open hole gravel pack well in deep water field to optimize production. Minimizing formation damage during the drilling and completion operation was a primaryconcern. In addition to preventing formation damage, the relative narrow pressure window, scaling tendency of formation water with divalent brines were concerns requiring the implementation of new fluid systems to mitigate the aforementioned issues. This required intensive laboratory design process and preplanning. Drilling and completion fluids were designed and customized based on results from tests previously mentioned. Compatibility between all fluids with formation water were assessed at 180, 225 and 250°F. Return permeability simulated drilling and completion sequences to prove non damaging properties. Logistic field challenges to handle systems were successfully managed in a remote location by sufficient pre-planning. Selected fluid systems were used in the field to successfully drill and complete the alpha beta open hole gravel pack well, with higher than expected production. Design process, results and field application parameters are discussed in this paper.
Learning from Field Measurements: Engineering Method to Improve Cement Returns in Riserless Deepwater Jobs
Authors: Dooply Mohammed , Peternell Ana , Long Jeffrey 
Published: September 2014

Abstract
With the increased importance of achieving zonal isolation in the shallow riserless sections of deepwater wells, it has become critical to understand the results of the cement placement. Riserless cementing job design has historically been a static process largely independent of the drilling parameters, particularly in these large-diameter boreholes.
Variable borehole shape and quality affects the wellbore cleaning, wellbore stability while drilling and the smooth operation of the casing run. Borehole quality can also compromise cement placement efficiency and mud displacement mechanics. It has become increasingly important to develop a greater understanding of the impact that borehole size and the identification of borehole degradation have in cementing design and placement, to increase the likelihood of achieving zonal isolation objectives.
Caliper tools provide an explicit method that uses physical measurements to evaluate not only wellbore quality but also formation characteristics. Caliper measurement is used to optimize the cementing design by adjusting key parameters such as cement slurry volumes, centralization, pre-flush volumes, and fluids pump rate, so that effective mud removal and optimized cement placement are achieved.
A review the current practices of field measurements and observations to understand and detect cement returns in the deepwater drilling environment and also the applications and key learnings from the engineering workflow led to new development of tools to improve the understanding of the cement volumes required for these particular top hole sections.
Planning for a Necessary Evil in Deepwater Operations: Remedial Cementing
Authors: Shine Joe 
Published: September 2014

AbstractDrilling operations are presented with challenges for both normal and complex wellbore environments with a focus on minimizing nonproductive time while successfully achieving the well objectives. In some cases, it is likely to reach the well objectives and remedial cementing may play a significant part whether it is due to exploration or wildcat-type wells, complex well construction, or the geological uncertainties. As a necessary evil, being able to plan for contingencies and success when faced with remedial cementing applications can reduce the potential replication of treatments and improve the extent of nonproductive time.When these situations arise during deepwater operations, there are challenges beyond the traditional cementing scope of work such as multiple temperature and pressure gradients, subsea equipment, and large-bore tubulars. Drilling deeper these factors may also include lithology, wellhead clearances, stuck pipe, failure of barriers, and/or an unstable well. Furthermore, traditional service tools find limited success with remedial operations in large-bore casing/tubulars, often requiring alternative solutions, including pumping through bottom hole assemblies, using inflatable packers, and developing other non-traditional placement techniques.This paper will present methods to improve the success of cement placement while performing remedial cementing operations in an effort to reduce nonproductive time and execute common contingency planning. In addition, specific well situations and events executing these methods will demonstrate the impacts to remediate the necessary evil.