A mathematical model which describes the dynamics of gas being circulated out of a riser is presented. The model is valid for conventional drilling where no backpressure is applied, controlled mud level (equivalent to dual gradient drilling), managed pressure drilling with backpressure, and with a riser gas handler. The presented model is validated with data from a field trial where gas was circulated down the drillstring and into an open riser with a reduced riser liquid level (controlled mud level). Underlying assumptions makes the models conservative. The model is suited to evaluate the procedures for use of a riser gas handler, and an example with automatic control of the rig choke shows how a gas kick can be safely circulated from the riser.
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.
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
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.
Shi, Jibin (Schlumberger) | Durairajan, Bala (Schlumberger) | Harmer, Richard (Schlumberger) | Chen, Wei (Schlumberger) | Verano, Fernando (Schlumberger) | Arevalo, Yezid (Schlumberger) | Douglas, Charles (Schlumberger) | Turner, Timothy (Schlumberger) | Trahan, Dexter (Schlumberger) | Touchet, Jude (Schlumberger) | Shen, Yuelin (Schlumberger) | Zaheer, Aamer (Schlumberger) | Pereda, Frank (Schlumberger) | Robichaux, Kirk (Schlumberger) | Cisneros, Dennis (Schlumberger)
Operators of Gulf of Mexico (GOM) wells frequently reported overtorque issue of bottomhole assembly (BHA) connections when drilling the 26-in. section through salt. Such overtorque often leads to costly tool damage beyond repair (DBR), additional trips, and high nonproductive time (NPT). The average DBR cost per BHA can be as high as USD 1 million. Combined with a complete BHA roundtrip, it can easily cost more than USD 3 million for operators if such failure happens. This has been a problem for several years and has caused significant damage: In 2014, of 15 26-in. PDC bit runs in salt, 40% had overtorque connections and 20% led to DBR. This paper discusses how an integrated multidisciplinary team identified the root cause of and the solution to the overtorque problem.
Torsional vibration was believed to be the cause of such failure. Comprehensive drilling dynamics simulation software that is based on empirical bit design knowledge was used to design a new bit to reduce the vibration. A newly developed high frequency downhole recording tool used in the 26-in. section recorded high-frequency torque, acceleration, and RPM fluctuation downhole. This dataset became the key to understanding the downhole vibration in detail because it provided information that cannot be acquired by a traditional MWD tool. Field-recorded data were fed into drilling dynamics simulations to accurately calibrate the drilling dynamics model. The simulations resembled downhole drilling conditions and clearly identified the root cause. The simulations precisely predicted the torque along the entire drillstring and identified why overtorque is present in only a certain part of the drillstring. The calibrated model was used to compare old and new bit designs. The newly designed bit showed much lower torque amplitude with similar torsional vibration frequencies. The simulation indicated that the newly designed bit can significantly alleviate the overtorque issue.
Implementation of the new bit mitigated the overtorque issue immediately. As of May 2016, there have been 18 runs with the new bit. Only one run had a slight overtorque issue whereas the rest showed no sign of overtorque connections. DBR and NPT related to overtorque were eliminated. As a byproduct, the average on-bottom rate of penetration increased by 9%. This case demonstrates the effectiveness of the integrated approach to solving drilling challenges.
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.
Annular pressure buildup (APB) in high-pressure/high-temperature (HP/HT) deepwater wells can result in wellbore failure, even during drill-ahead operations. Manufactured to collapse at a specific pressure and installed on the external casing wall, syntactic foam is an economical solution to mitigate APB and protect casing strings in offshore HP/HT wells. This paper focuses on the modeling and simulation of the effects of syntactic foam deformation on APB in casing/tubing annuli.
Syntactic foam is a composite material synthesized by filling a polymer, metal, or ceramic matrix with hollow glass microspheres (HGMSs). Under increasing hydrostatic pressure (HCP), the behavior of the foam material can be described using a HCP-strain curve typically consisting of three regions: linear elastic, plateau, and densification. A multisection linear model was established to express the volumetric strain vs. HCP relationship, which significantly simplifies the APB calculation while still ensuring sufficient accuracy. Analytical correlations were developed for the elastic compressibility and collapse pressure vs. temperature, which can generate feed-in data for the multisection linear model when only limited datasets are available.
A workflow was developed for the simulation of syntactic foam effects on APB in HP/HT wells. The syntactic foam models were implemented and integrated into a commercial casing and tubing design software platform. In a simplified example well, numerical simulation results were found to be consistent with the results from analytical calculation. In a case study of an offshore HP/HT well, numerical simulation demonstrates that syntactic foam is a viable and effective option for APB management. Combined with thermal flow and APB simulators, the implementation of the syntactic foam models enables more accurate casing/tubing load analyses. APB simulation including the effects of syntactic foam can provide valuable information to assist well design engineers in the design of HP/HT deepwater wells with long-term well integrity.
Wight, Jim (Halliburton) | Craddock, G. G. (Halliburton) | Haggerty, Dennis (Halliburton) | Rojas, Fabian (Halliburton) | Montiverdi, Jonathan (Halliburton) | Yadav, Arvind (Halliburton) | Magdaniel, Manuel (Halliburton) | Rios, Federico (Halliburton) | Harive, Kevin (Halliburton)
This paper discusses using a perforating toolkit as a computational paradigm to provide perforating solutions to field personnel. This toolkit provides an extensive list of charges and gun systems and generates the effects on the target rock and overburden pressure. Outputs include depth of penetration and casing hole sizes. It has an improved graphical user interface (GUI) and updated algorithms based on data from the flow laboratory.
The perforating toolkit uses up-to-date API data as the basis for the calculations; simulations are based on parameters set by the user and outputs are in a graphical format, showing the perforating performance within the reservoir. The perforating toolkit software is designed to use improved data obtained from recent laboratory testing. The most up-to-date flow laboratory testing was used to generate the algorithms for the perforating toolkit, generating more precise algorithms and producing improved perforation predictions. Testing involved a broader range of data than was previously used, allowing the software to make more accurate predictions. This new tool was benchmarked using laboratory testing, which demonstrated the quality of the paradigm and its functional use for improved downhole perforating. The software provides the field user with a tool to predict downhole shaped-charge performance quickly and in a cost-effective manner. The models also allow a number of parameters to be varied for a better comparison of different scenarios.
This paper discusses how new data across a broader range from the flow laboratory was used to improve the basic software algorithms and help provide the most accurate prediction of downhole charge performance.
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.