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.
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.
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.
This paper discusses a new generation of inflow control devices (ICDs), which are known as autonomous inflow control devices (AICDs) that can balance production flow and restrict the unwanted fluid. This paper describes the functional testing conducted to evaluate the performance of the fluidic diode type AICD for oil conditions of less than or equal to 1.5 cP and the restriction of unwanted gas in field-like conditions. It will also compare flow performance curves to those of a traditional nozzle-type ICD.
Unbalanced inflow from a reservoir can result in water or gas breakthrough, and unless this situation can be addressed satisfactorily, valuable reserves may be lost. When oil is producing from all zones, the AICD will behave as a passive ICD, thereby balancing flow. However, when lower-viscosity fluids break through, the AICD provides a choking effect, significantly reducing flow from the zone responsible for producing these undesirable fluids. Such autonomous characteristics enable a higher recovery rate of oil and also reduce the cost for processing the unwanted fluids. The AICD creates this change in production performance without control lines, moving parts, or electronics.
The AICD presented in this paper, also known as Range 1, has an innovative fluidic sensor that is highly sensitive to the fluid properties and is currently best suited for oil viscosities of 0.3–1.5 cP. The Range 1 AICD uses an autonomous on/off type switching function upon gas breakthrough to control gas inflow instead of a gradual change in total flow performance as provided by other inflow control device types. Oil flow is fed directly to the exit port of the AICD, while gas is "switched" to a highly restrictive, spinning path that limits gas production through the tool. Results from single-phase experimental flow testing with oil and nitrogen are presented and discussed. The test results demonstrate that the AICD is an effective tool for restricting gas production.
The discussion further shows that if technology, such as the new AICD, is applied to a well-completion design, total oil recovery can be enhanced by increasing the life of the well and reducing the production of undesirable fluids.
Sonnier, Paul (CSI Technologies) | Watters, Larry (CSI Technologies) | Clapper, Dennis (Baker Hughes) | Head, Bill (RPSEA) | Scherer, George (Princeton University) | Prod'homme, Robert (Princeton University) | Choi, Myoungsung (Princeton University) | Zhang, Zhidong (Princeton University)
The challenges of both primary and remedial cementing in Non-Aqueous Drilling Fluid (NAF) are well known in the deepwater industry. NAFs allow for stable drilling in high pressure high temperature (HPHT) and ultra-deepwater environments. However, mud properties that were beneficial for drilling become detrimental to completions. Fluid incompatibilities resulting from contamination, residue, fluid swapping and other fluid interactions can result in reduced compressive strength, channeling, downhole gelation and a poor cement bond. Incompatibility and incomplete hole cleaning can result in safety and environmental risks including job failure, future operational issues and loss of zonal isolation. Commercially available products are available to assist with mud displacement, however, there is a need for a fundamental characterization of mud-cement interactions on a chemical level to improve the knowledge of related technical risks and the technology required for risk reduction and long-term well integrity.
The objectives of this project are to develop fundamental knowledge of mud-cement compatibility issues related specifically to deepwater cementing, to quantify risks associated with cementing in NAF and to develop best practices and derive recommendations in order to reduce the recognized risks.
Large-diameter, long-interval tubing conveyed perforation (TCP) operations are an important part of modern deepwater completion design. Safe and cost-effective designs require an understanding of the interdependence between a large set of static and dynamic parameters that characterize the downhole processes affecting a complex well completion. Typically, it is impractical to measure such parameters in a downhole environment. For this reason, physics-based modeling and numerical simulation of transient processes such as static/dynamic underbalance, perforation cleanup, and shock loading are a critical component of the design process.
A significant challenge is that these downhole processes are typically modeled with a dynamically coupled system that includes the reservoir, wellbore, perforation tunnel, tool string and fractures, leading to long simulation times. This is not desirable due to the fact that a single design must satisfy constraints over a large design parameter space, and therefore requires many simulations. This paper introduces a fast computational tool based on dominant flow physics of the perforating process. The new model is benchmarked and verified against current industry-standard dynamic simulators, as well as computational fluid dynamic (CFD) packages.
The novelty of this approach is based on physics at the right scale, resulting in a computational efficiency improvement and simulation times at least an order of magnitude less than other industry-standard simulators. Results for numerical examples representing downhole perforating scenarios provide unique insight into underbalance (i.e., using pressure transients), and subsequent cleanup mechanisms.
In this study, a new fast computational model of the perforation process has been developed based on dominant physics. The benefits of this novel approach include design parameters that are closely tied to the flow physics, and simulation results that are easily interpreted for enhanced perforating job design. Ultimately, these benefits enable the completion engineer to make more informed and faster decisions during the design of a perforating job.
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.
When constructing deepwater wells, incompatibility between synthetic-based mud (SBM) and Portland cements can lead to poor cementation and loss of cement integrity, which in turn may compromise zonal isolation. An alternative cementitious material based on geopolymers has been developed with improved SBM compatibility for primary and remedial cementing purposes as well as lost circulation control. Geopolymer benefits go beyond mere SBM compatibility: it is in fact possible to solidify non-aqueous fluids such as SBM and oil-based mud (OBM) using geopolymer formulations. This also means that non-aqueous fluids (SBM, OBM) can be disposed of in a cost-effective way, which presents a viable option for environmentally acceptable on-site or off-site disposal of drilling muds and cuttings.
Geopolymer is a type of alkali activated material that forms when an aluminosilicate precursor powder (such as fly ash) is mixed with an alkaline activating solution (such as sodium hydroxide). A novel SBM solidification method was developed by blending varied amounts of geopolymer and SBM. This solidification method was tested with various sources of precursor powders, SBMs and OBMs. The rheology and strength of the geopolymer/SBM blends were measured under downhole conditions.
Strength testing results showed that geopolymer cement lost only 30% of its strength when blended with 10% SBM, while a neat Portland slurry lost 70% strength. Geopolymer/SBM blends containing up to 40% SBM were found to have measurable strength when cured under downhole conditions. By changing the amount of geopolymer and SBM in the slurry, the geopolymer/SBM system can be developed into a lost circulation treatment with low compressive strength, or into a primary cementation material with higher compressive strength.
The geopolymer/SBM blends at different mixing ratios have shown great improvement in rheology of the geopolymer cement, allowing for pumpability of the slurry for well cementation. For instance, 30% SBM blends have downhole rheology profiles that approach those of neat Portland slurries.
Hoxha, Besmir Buranaj (The University of Texas at Austin) | Incedalip, Oguz (The University of Texas at Austin) | Vajargah, Ali Karimi (The University of Texas at Austin) | Hale, Arthur (The University of Texas at Austin) | Oort, Eric van (The University of Texas at Austin)
Drilling through depleted zones in offshore deepwater prospects is becoming more common with ongoing production and field maturation, especially when deeper-lying, virgin-pressured reservoirs are explored and produced in later stages of field development. Some of the challenges associated with these depleted zones include severe mud loss and associated borehole problems, as well as troublesome cementing and poor zonal isolation. Artificially strengthening the wellbore is now becoming of crucial importance in order to successfully drill and cement deepwater wells in mature fields and any other wells with narrow drilling margins.
In this paper, we introduce an innovative thermal wellbore strengthening (TWBS) technique to elevate the tangential stress (also known as the hoop stress) near the wellbore, and consequently increase the fracture gradient. A "thermal fluid," consisting of a carrier mud with heat-releasing ("exothermic") coated particles, has been designed to target depleted zones and release heat at exactly the right time to increase near-wellbore thermal stress, which directly elevates the near-wellbore tangential stress and in turn elevates the effective fracture gradient. Ultimately, this lowers the risk of lost circulation and improves the chance of successfully cementing and achieving zonal isolation. For instance, a TWBS treatment can be executed as an integral part of the cement job by using it in an extended spacer train for mud displacement, pumped directly prior to cement placement.
The coated exothermic particles were designed such that they could release their "payload" via an extended time-release mechanism, to ensure that the heat release reaches the appropriate target location in the wellbore at the right time. The chemical systems, which are based on dissolving various hygroscopic salts in water, were tested and developed to heat up the wellbore and increase temperature up to 100°C. This will potentially elevate the fracture gradient by several hundred psi, depending on formation properties. Details regarding the formulation and testing of the non-coated, coated particles, and the carrier fluid are discussed; as well as considerations for TWBS field application.
In addition, a new computational heat transfer model was developed to calculate the temperature distribution within the rock formation and within the drillstring/work string and wellbore annulus, for a formation contacted by a fluid with particles that react in exothermic fashion. The new model calculates the transient temperature distribution, increase in near-wellbore stress, and fracture gradient for a given amount of heat generation by the fluid and temperature increase in the rock. It can assist with well design aspects of the proposed thermal wellbore strengthening technique, and is particularly helpful in estimating the downhole temperature variations and assessing its implications prior to job execution. Details of the model and results of several typical simulations are given herein.
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.