Determining Hole Size and Washout by Running a Fluid Caliper, for Cementing Purposes

2021 ◽  
Author(s):  
Jason Scott Ellison ◽  
Charles Ralph Ellison ◽  
Mike Davis ◽  
Carl Bird ◽  
Ryan J. Broglie ◽  
...  
Keyword(s):  
Human Error ◽  
Best Practice ◽  
The United States ◽  
Accurate Estimation ◽  
Drilling Fluids ◽  
Hole Size ◽  
Permian Basin ◽  
Lost Circulation ◽  
Well Design ◽  
Downhole Tool

Abstract This paper describes the procedure to perform a fluid caliper and how by using fluid dynamics concepts, average hole size can accurately be determined, helping to derive the amount of hole washout and the appropriate amount of cement needed to circulate or achieve desired cement height. This process has been successfully performed on over 40,000 Permian Basin wells in West Texas and Eastern New Mexico, as well as numerous other basins in the United States. This includes vertical, directional, and horizontal wells of varying hole sizes and depths, from surface to production hole. This paper will provide real world examples, discussion of geological formations encountered, drilling fluids used, and the ultimate benefit a fluid caliper provided each operator through the accurate estimation of cement volume for the reduction of waste and satisfaction of well design and regulatory requirements. This paper will demonstrate that fluid calipers add to the operational efficiency of most drilling operations and should be considered a "Best Practice" for most drilling programs as their use can greatly limit the need to remediate a cement job necessitating additional downhole tool runs, wasting additional valuable rig time. Also, to be addressed are the limitations of fluid calipers including lost circulation, turbulent flow, and human error. Cementing is an integral part of the process to ensure wellbore longevity, requiring increased attention. Field practice of pumping nut plug, dye, or other markers to estimate required volumes is outdated and inaccurate. This paper will clearly identify the reasons why the modern fluid caliper is aligned with today's heightened focus on ESG. Environmentally, fluid calipers determine the proper amount of cement to prevent waste. Regarding safety, fluid calipers help ensure the operator pumps accurate cement volumes to cover corrosive and/or productive zones to prevent unwanted annular influx, and referring to governance, fluid calipers help the operator pump adequate cement volumes to satisfy well construction regulations.

Successful Installations and Predictable Performance of Solid Expandable Drilling Liner in Greater Ekofisk Field, Offshore North Sea

2021 ◽  
Author(s):  
Eko Awan Fitnawan ◽  
Bjørn Holien ◽  
Harald Nevøy
Keyword(s):  
Design Strategy ◽  
Gas Content ◽  
Base Case ◽  
Hole Size ◽  
Lost Circulation ◽  
The Past ◽  
Track Record ◽  
Well Design ◽  
Collapse Resistance ◽  
Installation Time

Abstract Drilling the lower overburden section in specific parts of the Greater Ekofisk Area (GEA) fields can be very troublesome. Wells in these parts may intersect shales with high gas content in the upper section (requiring high mud weight) and unstable zones with massive lost circulation risk (requiring low mud weight) near the base of the interval. These challenges have raised the need for a contingency drilling liner to "split" the section in two parts. Rather than changing the basic well design, the operator fronted the development of an 8-5/8″ expandable drilling liner with high collapse resistance for this purpose. This string provides 8.514″ post-expansion drift ID that accommodate an 8 ½″ bit size for the reservoir section, which is critical for GEA well design strategy. In the past five years, the operator has successfully installed 31 800 ft of 8-5/8″ expandable liner in 27 different wellbores with near perfect track record. The average liner length installed is 1 140 ft per wellbore, with an average installation time of 2.8 rig days. The solid expandable tubular (SET) drilling liner has been utilized both as part of the planned well design and as contingency liner. It has, on occasions, been worked down with parameters outside the stated specifications and still been successfully expanded afterwards. The 8-5/8″ expandable liner is now a proven system and has been one of the key enablers to achieve well objectives by maintaining hole size in a predictable manner. It provides a better drilling window for reservoir drilling and reservoir liner cementing compared to a conventional 7-3/4″ liner alternative. It also enables further contingency solutions in case other difficulties arise in the reservoir section. This technical paper describes how the operator in the overcame a significant geological challenge by working with an expandable pipe supplier to develop a unique size and strength of expandable liner that fits with the base case GEA well design. The paper also reviews the installation experiences, associated risks, performance, and key learnings with expandable liners.

Business: The Electronic Health Record: Front Line Experience

2011 ◽  
Vol 21 (1) ◽  
pp. 18-22
Author(s):  
Rosemary Griffin
Keyword(s):  
Health Care ◽  
Information Technology ◽  
Electronic Health Record ◽  
Financial Incentives ◽  
Best Practice ◽  
Health Care Systems ◽  
The United States ◽  
Health Record ◽  
Health Trends ◽  
Electronic Health

National legislation is in place to facilitate reform of the United States health care industry. The Health Care Information Technology and Clinical Health Act (HITECH) offers financial incentives to hospitals, physicians, and individual providers to establish an electronic health record that ultimately will link with the health information technology of other health care systems and providers. The information collected will facilitate patient safety, promote best practice, and track health trends such as smoking and childhood obesity.

Article Commentary: Defining New Directions for More Effective Management of Surgical Pain in the United States: Highlights of the Inaugural Surgical Pain Congress™

2014 ◽  
Vol 80 (3) ◽  
pp. 219-228 ◽  
Author(s):  
Girish P. Joshi ◽  
David E. Beck ◽  
Roger Hill Emerson ◽  
Thomas M. Halaszynski ◽  
Jonathan S. Jahr ◽  
...  
Keyword(s):  
Patient Satisfaction ◽  
Pain Management ◽  
Best Practice ◽  
Task Force ◽  
Unmet Need ◽  
The United States ◽  
Cost Of Care ◽  
Inaugural Meeting ◽  
Surgical Pain ◽  
Wide Range

Despite advances in pharmacologic options for the management of surgical pain, there appears to have been little or no overall improvement over the last two decades in the level of pain experienced by patients. The importance of adequate and effective surgical pain management, however, is clear, because inadequate pain control 1) has a wide range of undesirable physiologic and immunologic effects; 2) is associated with poor surgical outcomes; 3) has increased probability of readmission; and 4) adversely affects the overall cost of care as well as patient satisfaction. There is a clear unmet need for a national surgical pain management consensus task force to raise awareness and develop best practice guidelines for improving surgical pain management, patient safety, patient satisfaction, rapid postsurgical recovery, and health economic outcomes. To comprehensively address this need, the multidisciplinary Surgical Pain Congress™ has been established. The inaugural meeting of this Congress (March 8 to 10, 2013, Celebration, Florida) evaluated the current surgical pain management paradigm and identified key components of best practices.

Failure Analysis of the Tripping Operation and its Impact on Well Control

2015 ◽  
Author(s):  
Majeed Abimbola ◽  
Faisal Khan ◽  
Vikram Garaniya ◽  
Stephen Butt
Keyword(s):  
Human Error ◽  
Integrated Control ◽  
Fault Tree ◽  
Fault Tree Analysis ◽  
Well Control ◽  
Lost Circulation ◽  
Critical Elements ◽  
Open Hole ◽  
Critical Components ◽  
The Cost

As the cost of drilling and completion of offshore well is soaring, efforts are required for better well planning. Safety is to be given the highest priority over all other aspects of well planning. Among different element of drilling, well control is one of the most critical components for the safety of the operation, employees and the environment. Primary well control is ensured by keeping the hydrostatic pressure of the mud above the pore pressure across an open hole section. A loss of well control implies an influx of formation fluid into the wellbore which can culminate to a blowout if uncontrollable. Among the factors that contribute to a blowout are: stuck pipe, casing failure, swabbing, cementing, equipment failure and drilling into other well. Swabbing often occurs during tripping out of an open hole. In this study, investigations of the effects of tripping operation on primary well control are conducted. Failure scenarios of tripping operations in conventional overbalanced drilling and managed pressure drilling are studied using fault tree analysis. These scenarios are subsequently mapped into Bayesian Networks to overcome fault tree modelling limitations such s dependability assessment and common cause failure. The analysis of the BN models identified RCD failure, BHP reduction due to insufficient mud density and lost circulation, DAPC integrated control system, DAPC choke manifold, DAPC back pressure pump, and human error as critical elements in the loss of well control through tripping out operation.

Wellhead Design Enables Offline Cementing and a Shift in Operational Efficiency

2021 ◽  
Vol 73 (05) ◽  
pp. 68-69
Author(s):  
Chris Carpenter
Keyword(s):  
Oil And Gas ◽  
Operational Efficiency ◽  
Asia Pacific ◽  
Significant Shift ◽  
Lost Circulation ◽  
Well Design ◽  
Geological Conditions ◽  
The Moment ◽  
Tubing Hanger ◽  
Column Pressure

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202439, “Pushing Malaysia’s Drilling Industry Into a New Frontier: How a Distinctive Wellhead Design Enabled Implementation of a Fully Offline Well Cementing Resulting in a Significant Shift in Operational Efficiency,” by Fauzi Abbas and Azrynizam M. Nor, Vestigo, and Daryl Chang, Cameron, a Schlumberger Company, prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. Traditionally, rigs are positioned over a well from the moment the surface casing is drilled until the installation of the wellhead tree. This results in the loss of precious time as the rig idles during online cementing. However, in mature Field A offshore Terengganu, Malaysia, a new approach eliminated such inefficiency dramatically. Operational Planning With oil production in Field A initiated in October 2015, historical data on well lithology, formation pressure, and potential issues during drilling were available and were studied to ensure that wells would not experience lost circulation. This preplanning is crucial to ensure that the offline cementing activity meets the operator’s barrier requirements. Petronas Procedures and Guidelines for Upstream Activities (PPGUA 4.0) was used for the development of five subject wells in Field A. In this standard, two well barriers are required during all well activities, including for suspended wells, to prevent uncontrolled outflow from the well to the external environment. For Field A, two barrier types, mechanical and fluid, allowed by PPGUA 4.0 were selected to complement the field’s geological conditions. As defined in PPGUA 4.0, the fluid barrier is the hydrostatic column pressure, which exceeds the flow zone pore pressure, while the mechanical barrier is an element that achieves sealing in the wellbore, such as plugs. The fluid barrier was used because the wells in Field A were not known to have circulation losses. For the development of Field A, the selected rig featured a light-duty crane to assist with equipment spotting on the platform. Once barriers and rig selection are finalized, planning out the drill sequence for rig skidding is imperative. Space required by drillers, cementers, and equipment are among the considerations that affect rig-skid sequence, as well as the necessity of increased manpower. Offline Cementing Equipment and Application In Field A, the casing program was 9⅝×7×3½ in. with a slimhole well design. The wellhead used was a monobore wellhead system with quick connectors. The standard 11-in. nominal wellhead design was used for the wells with no modifications required. All three sections of the casing program were offline cemented. They were the 9⅝-in. surface casing, 7-in. production casing, and 3½-in. tubing. The 9⅝-in. surface casing is threaded to the wellhead housing and was run and landed with the last casing joint. Subsequent wellhead 7-in. casing hangers and a 3½-in. tubing hanger then were run and landed into the compact housing.

scholarly journals Laboratory Study on Core Fracturing Simulations for Wellbore Strengthening

Geofluids ◽  
2019 ◽  
Vol 2019 ◽  
pp. 1-18 ◽  
Author(s):  
Biao Ma ◽  
Xiaolin Pu ◽  
Zhengguo Zhao ◽  
Hao Wang ◽  
Wenxin Dong
Keyword(s):  
Bearing Capacity ◽  
Laboratory Study ◽  
Drilling Fluid ◽  
Drilling Fluids ◽  
Lost Circulation ◽  
The Core ◽  
Fracture Pressure ◽  
Fluid Systems ◽  
Fracturing Process ◽  
Wellbore Strengthening

The lost circulation in a formation is one of the most complicated problems that have existed in drilling engineering for a long time. The key to solving the loss of drilling fluid circulation is to improve the pressure-bearing capacity of the formation. The tendency is to improve the formation pressure-bearing capacity with drilling fluid technology for strengthening the wellbore, either to the low fracture pressure of the formation or to that of the naturally fractured formation. Therefore, a laboratory study focused on core fracturing simulations for the strengthening of wellbores was conducted with self-developed fracture experiment equipment. Experiments were performed to determine the effect of the gradation of plugging materials, kinds of plugging materials, and drilling fluid systems. The results showed that fracture pressure in the presence of drilling fluid was significantly higher than that in the presence of water. The kinds and gradation of drilling fluids had obvious effects on the core fracturing process. In addition, different drilling fluid systems had different effects on the core fracture process. In the same case, the core fracture pressure in the presence of oil-based drilling fluid was less than that in the presence of water-based drilling fluid.

scholarly journals Production and application of manure nitrogen and phosphorus in the United States since 1860

2021 ◽  
Vol 13 (2) ◽  
pp. 515-527
Author(s):  
Zihao Bian ◽  
Hanqin Tian ◽  
Qichun Yang ◽  
Rongting Xu ◽  
Shufen Pan ◽  
...  
Keyword(s):  
United States ◽  
Greenhouse Gas Emission ◽  
Nutrient Balance ◽  
Animal Manure ◽  
The United States ◽  
Accurate Estimation ◽  
Total Production ◽  
Nitrogen And Phosphorus ◽  
Southern Us ◽  
Multiple Data

Abstract. Livestock manure nitrogen (N) and phosphorus (P) play an important role in biogeochemical cycling. Accurate estimation of manure nutrient is important for assessing regional nutrient balance, greenhouse gas emission, and water environmental risk. Currently, spatially explicit manure nutrient datasets over a century-long period are scarce in the United States (US). Here, we developed four datasets of annual animal manure N and P production and application in the contiguous US at a 30 arcsec resolution over the period of 1860–2017. The dataset combined multiple data sources including county-level inventory data as well as high-resolution livestock and crop maps. The total production of manure N and P increased from 1.4 Tg N yr−1 and 0.3 Tg P yr−1 in 1860 to 7.4 Tg N yr−1 and 2.3 Tg P yr−1 in 2017, respectively. The increasing manure nutrient production was associated with increased livestock numbers before the 1980s and enhanced livestock weights after the 1980s. The manure application amount was primarily dominated by production, and its spatial pattern was impacted by the nutrient demand of crops. The intense-application region mainly enlarged from the Midwest toward the southern US and became more concentrated in numerous hot spots after the 1980s. The South Atlantic–Gulf and Mid-Atlantic basins were exposed to high environmental risks due to the enrichment of manure nutrient production and application from the 1970s to the period of 2000–2017. Our long-term manure N and P datasets provide detailed information for national and regional assessments of nutrient budgets. Additionally, the datasets can serve as the input data for ecosystem and hydrological models to examine biogeochemical cycles in terrestrial and aquatic ecosystems. Datasets are available at https://doi.org/10.1594/PANGAEA.919937 (Bian et al., 2020).

scholarly journals Numerical Modeling of Foam Drilling Hydraulics

2007 ◽  
Vol 4 (1) ◽  
pp. 103 ◽  
Author(s):  
Ozcan Baris ◽  
Luis Ayala ◽  
W. Watson Robert
Keyword(s):  
Drilling Fluid ◽  
Operating Conditions ◽  
Drilling Fluids ◽  
Drilling Mud ◽  
Lost Circulation ◽  
Pressure Profiles ◽  
Drilling Operations ◽  
Parametric Studies ◽  
Bit Life ◽  
Foam Drilling

The use of foam as a drilling fluid was developed to meet a special set of conditions under which other common drilling fluids had failed. Foam drilling is defined as the process of making boreholes by utilizing foam as the circulating fluid. When compared with conventional drilling, underbalanced or foam drilling has several advantages. These advantages include: avoidance of lost circulation problems, minimizing damage to pay zones, higher penetration rates and bit life. Foams are usually characterized by the quality, the ratio of the volume of gas, and the total foam volume. Obtaining dependable pressure profiles for aerated (gasified) fluids and foam is more difficult than for single phase fluids, since in the former ones the drilling mud contains a gas phase that is entrained within the fluid system. The primary goal of this study is to expand the knowledge-base of the hydrodynamic phenomena that occur in a foam drilling operation. In order to gain a better understanding of foam drilling operations, a hydrodynamic model is developed and run at different operating conditions. For this purpose, the flow of foam through the drilling system is modeled by invoking the basic principles of continuum mechanics and thermodynamics. The model was designed to allow gas and liquid flow at desired volumetric flow rates through the drillstring and annulus. Parametric studies are conducted in order to identify the most influential variables in the hydrodynamic modeling of foam flow. 

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