Murphy, Suzanne (Hess Corporation) | Hall, Elizabeth (Hess Corporation) | Gee, Ryan (National Oilwell Varco) | Nicklas, Jeffrey (National Oilwell Varco) | Shipe, Jason (National Oilwell Varco) | Skyles, Lane (National Oilwell Varco)
Given the high cost of drilling in any offshore environment, operators require reliable tools that can be utilized safely. Operators also want a tool that can excel in rigorous offshore drilling operations while being user friendly. Reliability of hydraulic drilling jars can improve by adding an internal component to the jar which will release the jar before it reaches its maximum over-pull load. An added benefit of this component is it also makes the tool more user friendly. Concerning safety, the fewer components that are external to the tool, the safer the tool becomes. Specifically, removing the need for an external safety collar eliminates a safety hazard by preventing an overhead object from falling to the rig floor. Finally, excelling in the rigorous offshore environment can come from a jar that is designed to hit harder than ever before.
This paper introduces a hydraulic drilling jar that includes the latest technology related to safety, reliability and strength. Safety aspects of the tool are presented as well as a module internal to the tool that improves its reliability. This module also makes it easier for the driller to operate the jar. The engineering principles that explain why this jar has an improved hitting force are also presented. The paper closes with a section dedicated to field results received from the Gulf of Mexico. A cost savings analysis is also be presented showing how certain features of this jar provide the operator with a more efficient use of rig time.
Recognizing the potential for, mitigating, or preventing weight material sag plays a critical role in the safety and success of many wellbore configurations. Accessing hydrocarbon reserves in deeper and ever extending reaches presents new challenges of narrower operating windows and hostile environments (higher pressures and temperatures). As a result, drilling fluids for these applications must possess an elevated degree of barite sag minimization. This paper reviews barite sag testing methodologies and discusses their relationship to field applications.
While it has been demonstrated that wellbore conditions, characteristics of the weight material used, and fluid type were all factors affecting settling rates in any given drilling fluid, there are still discussions on what single evaluation method or test might best qualify its potential to sag.
Various barite sag evaluation methods and techniques have been developed, used, and some even recognized as industry standards to assess the potential of weight material settling in drilling fluids. Because of the increasing variety of evaluations methodologies, it is timely to review the relationship between these actual laboratory measurements and field engineering of drilling fluids to recognize the potential for, minimizing, and managing weight material sag.
In this review, synthetic-based drilling fluids engineered to exhibit various types of rheological profiles were tested using a variety of methodologies for dynamic and static weight material settling. Relationships between the composition, rheological properties, and predisposition of the fluids tested to sag were established.
While the data from the tests detailed in this paper suggest clear differentiation between the key properties that most affect static and dynamic settling, the interpretation regarding the selection of a particular testing methodology were more subtle. It was observed that some of the results correlate better with actual wellbore conditions in which either static or dynamic sag would occur than with common drilling fluids engineering best practices. It was also confirmed that sag remains a very complexe phenomenon with a multiplicity of variables making it challenging to indubitably qualify the sag potential with just one single laboratory test.
In the Gulf of Mexico, the Paleogene play presents challenges in narrow drilling margins. To overcome the challenges, a fully integrated Managed Pressure Drilling (MPD) packaged system was incorporated into a deepwater drill ship. The MPD system was designed to drill a deepwater, high pressure / high temperature well in the Gulf of Mexico. This paper will explain the lessons learned, the challenges and improvements carried out through the use of the MPD system in three key areas: advanced wellbore pressure modeling, downhole characteristics fingerprinting using downhole data and the MPD equipment. A full MPD system was designed to comply with all new government regulations and its performance proven through successful cased hole and open hole testing. Upon government approval, the new system was used to drill the well in full MPD conditions, where the mud weight (MW) was brought below pore pressure and the well was balanced with applied surface back pressure. Throughout the well, there were numerous lessons learned in three key areas: wellbore hydraulics modeling, downhole characteristics provided by PWD data, & the MPD equipment. An advanced wellbore pressure model was needed to accurately maintain the appropriate downhole pressure through the application of surface backpressure. The system used this model to perform simulations and applied the results of those simulations to control the surface equipment. Downhole Pressure While Drilling (PWD) data provided verification of the modeling results and applied surface back pressure as the well was drilled. Challenges faced during the operation included pressure compensation due to swab and surge as a result of pipe movement, and fluid inertia coupled with compressibility of the mud. The downhole characteristics of the well were tracked through PWD data, which was important in compensating the backpressure during connections and drilling. Further, the downhole data were consistently used to fine-tune and adjust the applied back pressure to ensure the well did not go underbalanced during these operations. Continuous improvement during operations also led to increased reliability of the MPD equipment.
Dooply, Mohammed (Schlumberger) | DeBruijn, Gunnar (Schlumberger) | Flamant, Nicolas (Schlumberger) | Elhancha, Anouar (Schlumberger) | Rahman, Sharifur (Chevron U.S.A. Inc.) | Duan, Ming (Chevron U.S.A. Inc.) | Koons, Brian (Chevron U.S.A. Inc.)
One of the well construction challenges facing today's deepwater drilling environment is the need for multiple casing strings and drilling liners reaching the reservoir zones at greater depths. This challenges cement placement and fluid displacement for achieving zonal isolation confidence across prospective intervals having narrow pore and fracture pressures margins and higher equivalent circulating densities (ECD).
Dual gradient in this paper refers to one hydrostatic gradient of seawater density that begins at rig floor and a second hydrostatic gradient of mud density that begins at seafloor. Cement placement with dual gradient mode technically follows similar steps and principles as single gradient cementing. However, dual gradient will add a certain complexity to the operations as the result of the following factors:
The entire cement placement is on vacuum, i.e. the pumped fluids are continously U-tubing (free falling) due to hydraulic pressure imbalance that exists between the tubing and annulus continuously as such no surface pressure can be observed until the very end of displacement.
Darts and plugs shearing indications may not be noticeable through surface pressure signature.
Pronounced U-tubing can result in excessive fluid velocity, hence excessive friction and potentially breaking the formation.
Downhole anomalies are sometimes only detected from the subsea pump rate and active pit volume changes.
The above considerations must be taken into account under different job configurations and scenarios. Real-time monitoring of job parameters is crucial to understand downhole cement placement and fluid displacement, in order to make quick and informed decisions towards achieving successful cement placement.
A cementing hydraulics simulator is critical to understanding pressures, fluid flow rates and temperature during the cement job. A cementing hydraulics simulator has been developed specifically for dual gradient cementing application. The cementing hydraulics simulator plays a critical role to predict, in addition to cementing hydraulics and temperature, the vacuum length and the subsea pump inlet pressure and rate response throughout cement placement. The simulator can also account for the effect of compressible fluids and internal constrictions on surface and downhole pressures responses.
This paper will briefly explain the dual gradient drilling concept with associated cementing challenges and potential advantages. The cementing hydraulics simulator is capable of computing and displaying dual gradient pressure profile in deepwater environment. This requires understanding U-tubing during pre-job mud circulation and cementing stages, subsea pump inlet pressures and rates responses, Equivalent Circulating Density (ECD) during circulation with different subsea pump inputs setup, optimum circulation rate, bottom-hole pressure and differential pressure at any depth of interest and finally wellbore integrity.
This paper presents the results of a joint industry study with the American Petroleum Institute (API) and the National Energy Technology Laboratory (NETL) to assess three sets of field-generated foamed cement at in-situ conditions using surface operations. In this data set, industrial bottled N2 gas was used to generate the field samples versus the cryogenic nitrogen in previous tests. The advantage in using bottled N2 was the ability to mix and pump at lower rates while maintaining an accurate nitrogen delivery, thus allowing collection of low quality foamed cement samples. Foam quality is a measure of the ratio of gas to slurry. Additionally a static capture manifold or split manifold was used for the foam capture which allowed for foam isolation while maintaining the defined rates and pressures. This also gave the ability to maintain the capture pressure during transfer of the samples to the pressurized containers. A foam accumulator chamber was added to the static capture manifold and was charged with foam and subsequently displaced with N2 while filling the sample cylinder.
This paper presents results of X-ray Computed Tomography scans of the constant pressure sample cylinders which showed that collection processes have a dramatic influence on the structure of the cured foamed cement. Physical properties such as porosity and permeability, were also measured and indicate a strong relationship between foam quality and homogeneity of the samples. This research will ultimately offer the ability to predict the behavior of foamed cements under
Properties of foam cement are of particular importance to the zonal isolation and mechanical integrity of wellbore cements used in offshore applications. This paper presents an assessment of physical and mechanical properties of field generated foam cements. These properties are measured to determine the performance of cements generated at field conditions, and for comparison with data sets obtained from laboratory-generated cement. These measured properties are also integral data for the development of empirical relationships used to estimate the properties of cements existing in the wellbore.
Measurements of mechanical properties include both dynamic and static testing methods. Dynamic testing of Young's modulus, Poisson's ratio, and other mechanical and physical properties are performed under cyclic effective pressures from 6 – 48 MPa. Dynamic measuring practices utilize ultrasonic velocity measurements at 4 MPa intervals during pressure cycling. Static methods perform strain measurements under uniaxial loading, and are used for strength analysis and comparison with dynamic measurement results. Laboratory-generated cements were mixed according to API-RP-10B-2 and 10B-4, using a Class H Portland cement system. Field-generated samples were obtained from industry collaborators.
Results indicate irreversible changes to permeability and Young's modulus over the course of pressure cycling. These systematic variations provide insight into how foam cement properties may be altered when exposed to pressure variations within the wellbore. Empirical relationships are developed between parameters such as compressive strength, permeability, porosity, p-wave velocity, and Young's modulus for foam cements using linear and non-linear least-squared regression analysis. Preliminary empirical relationships show strong associations between compressive strength and each of the various properties of interest. This is a promising development in efforts to predict the properties of in-situ cements.
This assessment of mechanical and physical properties of field-generated foam cement provides an in-depth look at cements generated at simulated in-situ pressure conditions. A comparison of field- and lab-generated cement properties provides information about how representative lab-generated cements are of typically-unavailable field samples. The empirical relationships reported in this study may help to provide, using the few measured properties of placed cements, a method of estimating physical and mechanical properties. This information is intended to aid cement design and wellbore planning for more reliable wellbores.
With the rapid increase in number of major development projects in soft sand reservoirs in the last 20 years the industry has had to develop a range of sand control completion technologies to deliver high rate, reliable wells to support the production and injection. Sand control completion systems for production wells are generally mature and are broadly speaking typically successful. The development of reliable sand control systems for water injections wells has however typically proven to be significantly more challenging and this has impaired the economics of multiple projects by either necessitating the installation of more water injection wells, the periodic remedial repair of existing injection wells or suffer the inevitable impact on production rates and reserves recovery.
In many locations Cased Hole Fracpack (CHFP) or Gravel Pack (GP) completions have proven to have the capability to deliver high rate water injection wells. However, their long term reliability is often compromised due to the loss of the annular pack proppant when injecting water above formation fracture pressure. The loss of the annular pack proppant compromises the sand control system and reduced injection rates and formation fill in the wellbore typically soon follow.
In order to address this issue of annular proppant pack loss, a project was initiated to develop and qualify a proppant system that would remain immobile in the casing to screen annulus of CHFP/GP completions over life of well even when injecting water at high rate (in excess of 30,000 bbl/day) above formation fracture pressure.
Potential solutions from both inside and outside the oil and gas industry were reviewed and put through a rigorous program of lab based screening tests. Successful products progressed to the second stage qualification process of further lab scale and larger yard scale testing.
The final phase of the qualification process involved taking the preferred proppant product, a new generation resin coated proppant activated by a combination of a chemical activator additive in the fracturing fluid and temperature, and performing two onshore field trial operations which included several months of high rate water injection. The first installations of the new proppant product in deep water injection wells are expected from 2016 onwards.
One of the main challenges in the program was how to demonstrate suitability for both the installation process and life of well down hole service conditions in the lab and yard environment in a short time frame. This demanded the development and construction of a wide range of novel test procedures and apparatus. The results of this qualification and testing program will be discussed in this paper.
Three-dimensional (3D) finite element analysis (FEA)-based shock software is the next step in downhole shock modeling. This software uses a finite element and a fluid tool that simulates gun behavior on gun strings and adjoining tools, including perforation and subsequent stress conditions. By examining temporal stress predictions at element locations, failures can be estimated based on these numbers. On a recent perforating operation, there was an undesired event that resulted in a collapse of the spacer section within the perforating string. The event flattened spacers, but did not ruptured them, resulting in not damage to other sections. This event highlights how localized dynamic forces could be over looked in the present 1D industry dynamic modeling software. As part of the planning process, the current industry standard shock software was used to simulate the string and predict the likelihood of failure. The models showed no failure flags; additionally, post-operation models did not predict the downhole events that occurred. As part of the investigation into the events, this modeling shock software was used to provide a more detailed model of the event. These models provide a full 3D representation of the string and allow a much more detailed understanding of the pressures and stresses during the perforating event. The models clearly showed the string design was not optimized for the localized dynamic event and there was a risk of collapse. Pressures were plotted as a function of time at locations on the outside of the spacers, safety spacer, and loaded guns. The results showed pressures outside the spacers, which exceeded static threshold values and lasted for extended durations. Other regions, such as the safety spacer, did not show this effect at above static threshold magnitudes. As well as being able to reproduce the collapse event , work was taken a step further to examine mitigation designs that could be used to help prevent these types of issues. It was possible to test several of these designs using the 3D FEA-based shock software to validate their functionality.
The rheological properties of drilling fluids are crucial parameters in offshore operations, especially in the extreme conditions encountered during deepwater drilling. Oil based muds (OBM) are almost exclusively used in deepwater drilling operations, owing to such factors as their improved temperature stability, effectiveness when drilling through water sensitive formations, and capability to be utilized in narrow-margin drilling. A desired property of the drilling fluid is a minimal sensitivity of the flow properties with respect to temperature, leading to a flat-rheology system. Chemical additives provide the basis for the fluid's rheological properties, but are rarely addressed in detail within published literature. This paper reviews the chemistries of existing additives and their claimed uses. In addition to addressing the current state of the art, results are presented from an investigation into the effects of such emulsifier chemistries upon the rheological properties of the drilling fluid. This includes work on a novel emulsifier and comparative data to an industry standard incumbent. Through an improved study of the chemistry, a design-based approach can lead to the development of optimal properties for these high performance invert emulsion drilling fluids.
During a drilling campaign in the southern North Sea involving installation of two additional conductors inside a mono-tower, significant challenges to the operator were encountered. The mono-tower is a hydrocarbon production platform with six slots. The slots are located inside the foundation pile, extending above sea level, and were driven into the seabed using an impact hammer. Structural integrity of this foundation pile over the platform operating lifetime is paramount.
The basis of the well is its conductor, which is typically installed using the drill/drive method with an impact hammer followed by soil drillout. Offset installation challenges in the mono-tower deemed using the drill/drive method ineffective for this new well. An alternative method for installing conductors is the drill/grout method. However, drilling an open hole increases the possibility of massive washout or hydraulic fracture. The fluids provider designed a water-based mud (WBM) system customized for rapid fluid-loss prevention, thus strengthening the wellbore, maintaining hole integrity, and preventing hydraulic fracture.
In subsea or conventional platform wells, fluids return at the seabed without additional hydrostatic pressure. Because of drilling inside the foundation pile, the lowest achievable elevation for fluid returns is at the top of the foundation pile. Fluid flow into the formation can lead to degradation of the soil-bearing strength around the single foundation pile and adjacent wells. This could potentially lead to subsidence of the mono-tower or buckling of the existing wells. In case of experiencing ever losses a contingency plan was in place with a decision tree used to determine the most appropriate formulation and sequence of lost circulation material (LCM) pills, with setting cement plugs as a last resort. Installing the two additional conductors with that rig could have impaired the structural integrity of the platform foundation pile. The drilling mud design played a vital role in managing this risk.
The uniqueness of the fluid design helped deliver the section without wellbore instability issues, hence avoiding losses or hole collapse, requiring reactive measures. The results demonstrated that wellbore pressure containment and full hole integrity can be achieved when drilling unconsolidated sands.
The novelty of the technical process and fluid design approach acted as a barrier to help prevent losses and proved the theory of wellbore stabilization and strengthening in unconsolidated sands through field applications.
This paper focusses only on discussing the application of an engineered fluid solution through a rigorous technical approach, which contributed to the success during such critical operations.