bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evolution of Multistage-Fracture Completions in a North Sea Environment
Authors: Carpenter Chris 
Published: February 2016

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 170641, “The Evolution, Optimization, and Experience of Multistage- Fracturing Completions in a North Sea Environment,” by T.R. Koløy, K. Brække, T. Sørheim, and P. Lønning, Trican, prepared for the 2014 SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. The paper has not been peer reviewed.
This paper reviews two newly developed novel completion systems that significantly reduce time spent performing multistage stimulation in environments where cost and consequence of failure are high. Both coiled-tubing and wireline-manipulated sliding-sleeve/valve systems and balldrop-actuated systems have been developed and deployed, depending on the various completion and stimulation challenges faced. Since their first installation in 2009, these systems have been proven and refined in multiple wells for two major operators.
Background
For many of the fields requiring stimulation in the North Sea, cemented plug-and- perforation (plug-and-perf) completions have been used historically. It is a flexible solution in terms of the various types of stimulation designs that can be accommodated. However, because of the large number of perforating runs required, the bridge-plug setting, the retrieving or milling involved, and the clean out runs required, it is also a very time-consuming option. The turnaround times per stage have been widely documented and often range from 3 to 7 days.
Prototype Development, Testing, and Qualification. Sliding sleeves have been used for flow-control purposes in oil and gas wells for decades. Although sliding sleeves are simple in design, many users have questioned their reliability, and they did not see much use for fracturing operations until the mid-2000s, when ball-drop-actuated sliding sleeves entered the market. The preferred method for stimulating a reservoir with a cemented liner—stage by stage—has been with plug-and-perf methods. Plug-and-perf provides a proven method of initial stimulation, compartment for compartment, but provides no solution for efficient production management over the life of the well.
Development of a Stranded Tight Gas Field in the North Sea With Hydraulic Fracturing
Authors: Carpenter Chris 
Published: February 2016

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 170852, “Development of a Stranded Tight Gas Field in the UK Southern North Sea With Hydraulic Fracturing Within a Subsea Horizontal Well: A Case Study,” by Marc Langford, SPE, Douglas Westera, SPE, and Brian Holland, SPE, Centrica Energy, and Bogdan Bocaneala, SPE, and Mark Norris, SPE, Schlumberger, prepared for the 2014 SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. The paper has not been peer reviewed.
There are more than 100 accumulations in the southern North Sea that are flagged as stranded fields. One of these stranded tight gas fields, the Kew field, has been developed successfully with the use of a subsea well, horizontal drilling, and hydraulic fracturing. Because this was a subsea development well, all the hydraulic-fracturing operations had to be performed with the rig in place. The utmost efficiency of the operations was paramount; otherwise, the economics of the project would be affected negatively.
Well Overview
The Kew field is a gas field, with small volumes of associated condensate, located in Blocks 49/4a, 49/5a, 49/5b, and 49/4c of the UK continental shelf. It lies 120 km east of the English coast and 5 km west of the UK/Netherlands median line. The field location is pictured in Fig. 1. (For further geological and geophysical details of the Kew field, please see the complete paper.)
The planned Kew 49/04c-7Y subhorizontal development well was drilled along the crest of the Kew structure and is a sidetrack of the existing (suspended) Kew appraisal well 49/4c-7z.
The planned sidetrack 49/04c-7Y was initially intended to target the Lower Carboniferous units. To maximize reservoir contact, the well was initially planned to be completed with four to five hydraulic fractures, with a minimum of one per target unit. Because of the proximity to the gas/water contact, the decision was made to complete the well with a cased-and-cemented liner and plug-and-perforation technique for placement and isolation of the hydraulic fractures. Previous experiences with openhole uncemented multistage systems have positively affected the efficiency of hydraulic-fracturing execution in the North Sea. Also, previous experience of spalling and out-of-gauge hole was another driver toward a cemented system.
Cluster Liquefied Natural Gas: A New Paradigm for Small- and Medium-Scale LNG Business
Authors: Carpenter Chris 
Published: February 2016

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 171510, “Cluster Liquefied Natural Gas: New Paradigm for Small and Medium Liquefied-Natural-Gas Business,” by JungHan Lee, LNG Solutions, prepared for the 2014 SPE Asia Pacific Oil and Gas Conference and Exhibition, Adelaide, Australia, 14–16 October. The paper has not been peer reviewed.
Small- and medium-scale liquefied natural gas (LNG) is different from conventional LNG in trading distances, target markets, and application areas. Small- and medium-scale LNG may better coordinate needs between regional gas producers and consumers. Cluster LNG is a new concept of LNG technology suitable for emerging market environments. High performance of cluster LNG originates from higher liquefaction temperature and the adoption of efficient refrigerants for the temperature ranges. The inherent high performance of cluster LNG enables low capital expenditure (CAPEX) and low operational expenditure (OPEX).
Background
Small-scale LNG has so far constituted only a minor portion of global LNG production. However, there are many necessities of regional energy infrastructures and technologies that are different from those of traditional LNG. In Southeast Asian countries, natural gas and LNG sometimes compete with diesel oil rather than large-scale pipeline gas or large-scale LNG. At the same time, there are many small scattered gas sources remaining to be monetized for domestic markets in the region. Nevertheless, these domestic gas fields have not been developed properly so far because of small units of production and, as a result, high cost per unit. In this regard, new technologies suitable for small- and medium-scale LNG development may be necessary.
LNG for global exports and LNG intended for regional demands may need different approaches. Typical large-scale LNG aims to export at a radius up to 10 000 km; on the other hand, small- and medium-scale LNG may need only a 500- to 2 000-km radius.
Purification of Natural Gas by Use of Carbon-Molecular-Sieve Membranes
Authors: Carpenter Chris 
Published: February 2016

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 172085, “Purification of Natural Gases by Use of Carbon-Molecular-Sieve Membranes,” by Subrata Mondal and Kean Wang, The Petroleum Institute, Abu Dhabi, prepared for the 2014 SPE Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 10–13 November. The paper has not been peer reviewed.
Carbon-molecular-sieve membranes (CMSMs) are a promising candidate for natural-gas purification because of their excellent stability, permeation selectivity, and permeability. In this project, two CMSM samples were synthesized at different pyrolytic conditions and examined for separation of N2/CH4 gas pairs. Analysis revealed that both surface diffusion and molecular sieving play important roles in gas-permeation mechanisms, which results in abnormal behaviors in the selectivities of different gas molecules.
Introduction
Because of its abundance in natural reservoirs and relatively clean-burning nature, natural gas (NG) (CH4&gt;70%) is becoming increasingly important to the global energy supply. Raw NG contains such impurities as carbon dioxide (CO2), hydrogen sulfide (H2S), H2O, and N2, which can result in health hazards, corrosion of equipment, and lower heating value. The concentration of these impurities varies considerably in NGs produced at different locations but should be reduced to certain levels before shipment.
Currently, large-scale NG- processing plants employ such technologies as adsorption (e.g., dehydration), absorption (e.g., amine wash for the removal of H2S and CO2), and cryogenic distillation (e.g., N2 removal). Although these technologies are mature and effective, they are expensive, energy-intensive, and environmentally unfriendly. For example, an N2- removal unit (NRU) generally operates at temperatures lower than –150°C, while the amine-wash unit requires constant maintenance and solvent replenishing.
Membrane technology offers great advantages for NG processing. It is compact, easy to install or scale up, and requires minimal space, energy input, labor, and maintenance resources. These attributes make it particularly attractive for offshore and remote gas fields. Currently, membrane modules for CO2 removal are commercially available and are the dominant technology in offshore applications even as they become more important in onshore applications. However, improvements are needed to compete with the current technologies in large-scale, inland NG-processing plants.
Design Methods for Subsea Equipment for Extreme and Survival Load Conditions
Authors: Carpenter Chris 
Published: February 2016

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 25352, “Design Method and Load- and Resistance-Factor Design for High-Pressure/High-Temperature Subsea Equipment for Extreme and Survival Load Conditions,” by Parth D. Pathak and Samuel L. Taylor, OneSubsea, prepared for the 2014 Offshore Technology Conference, Houston, 5–8 May. The paper has not been peer reviewed.
This paper posits a design method for subsea equipment governed by American Petroleum Institute (API) Specification (spec.) 17 (and particularly 17D). Fatigue-life estimation is also addressed for these conditions. An analysis of a subsea-tree component is reviewed, evaluating its combined load capacity for normal, extreme, and survival conditions. Additionally, the fatigue life-cycle estimation for this component is included.
Introduction
The API spec. 17D and spec. 6A provisions have been the governing terms for subsea trees and wellheads, providing the design guidelines for normal operating conditions up to 15,000 psi. The recently published API Technical Report (TR) 1PER15K-1 and TR 17TR8, the latter still under development, address the design methodology for normal operating high-pressure/ high-temperature (HP/HT) conditions. But these specifications and technical reports do not provide design guidelines for extreme and survival operating conditions. This paper tries to address design methods for subsea equipment that falls under API spec. 17, with focus on subsea trees and wellheads for such conditions.
API Recommended Practice (RP) 17G, which is intended for design of completion and workover risers, addresses these extreme and survival load operating conditions. It provides the equipment’s normal, extreme, and survival operating capacities on the basis of safety factors applied to the ultimate capacity. It also provides allowables based on yield strength with condition factors for extreme and survival conditions. This paper provides a methodology whereby the design factors for the extreme and survival load conditions from API RP 17G are adapted so that they can be applied to API spec. 17D equipment. Because testing the API spec. 17D equipment to its ultimate capacity is not easily feasible, an elastic/plastic analysis method based on American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (BPVC) Section VIII, Division 2 or Division 3 (ASME Division 2 or 3) is suggested to determine the ultimate capacity of the equipment.
Efficient Drilling of Ultra-HP/HT Wells in the Gulf of Thailand
Authors: Carpenter Chris 
Published: February 2016

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 25392, “Efficient Drilling of Ultra-HP/HT Wells in the Gulf of Thailand,” by Joy Araujo, Schlumberger; Keittipong Kaotun, PTTEP; and Panupun Dumrongthai and A. Adrian, Schlumberger, prepared for the 2014 Offshore Technology Conference, Houston, 5–8 May. The paper has not been peer reviewed.
A new measurement-while-drilling (MWD) tool has been designed that can operate reliably at 200°C and 207 MPa, providing real-time direction and inclination surveys, azimuthal gamma ray, annular and internal pressure while drilling, and shock and vibration measurements. An operator in the Gulf of Thailand used this new MWD technology to drill wells in ultrahigh-pressure/high-temperature (HP/HT) reservoirs without the need to stop operation because of temperature limitations. Savings of ½ day per well have been achieved.
Introduction
Offshore drilling in the Gulf of Thailand increasingly challenges logging operations, with temperatures greater than 200°C. Hundreds of wells need to be drilled per year in this environment to fulfill long-term gas contracts. High efficiency is required in such a high-volume operation.
Existing commercial MWD and logging-while-drilling (LWD) technologies are only capable of operating up to 175°C, with an inherent decrease in reliability at higher temperatures. In the planned ultra-HP/HT projects, the bottomhole assembly (BHA), which includes an MWD tool for directional and inclination measurements in real time, will be pulled out of the hole once the circulating temperature reaches 175°C. Then, a new BHA, without measurement tools, will be used to continue drilling to total depth. This “blind” drilling section could be several hundred meters long, introducing risks associated with well control and well collision.
The main limiting factors in having MWD/LWD tools operating in these ultra-HP/HT environments are the downhole electronic components. Industry research studies show that plastic-encapsulated components have a life expectancy of approximately 1,000 hours at 150°C; this drops to less than 100 hours at 175°C. Ceramic-encapsulated components last longer at 175°C, but they are bigger and heavier than their plastic counterparts. Because space is restricted in these tools, the best compromise yields a mix of both ceramic- and plastic-encapsulated components.
To find a solution to this industrywide problem, significant effort was made over the last decade to develop custom electronics that can withstand high downhole temperatures. The newly developed MWD tool equipped with these novel electronics components was deployed in ultra-HP/HT wells. In these wells, the real-time measurements were necessary to drill the sections with operating temperatures greater than 175°C. It allowed minimization of drilling risks, enabled proper well placement, and improved drilling efficiency by eliminating one run.
Improving Drilling-Operation Efficiency by Use of a Mud Cap
Authors: Carpenter Chris 
Published: February 2016

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 167985, “Improving Drilling-Operations Efficiency on an Ultranarrow- Margin HP/HT MPD Well by Use of a Mud Cap,” by Joy Oyovwevotu, SPE, Senergy; Eric Low, SPE, Bowleven; and Steve Nas, SPE, Schlumberger, prepared for the 2014 SPE Drilling Conference and Exhibition, Fort Worth, Texas, USA, 4–6 March. The paper has not been peer reviewed.
This paper describes the planning and execution of use of mud-cap fluid in the drilling of an ultranarrow-margin (0.50-lbm/gal window at the planning stage) high-pressure/ high-temperature (HP/HT) well from a jackup rig. Significant operational efficiency was gained from the use of cap fluids, making it possible to drill a well that otherwise would have been nearly impossible to drill with minimum lost time.
Introduction
The IM field is located in Block MLHP-7 in the Rio Del Rey basin offshore Cameroon in a water depth of 58 m (Fig. 1). At the target reservoir level, Well IM-5 was predicted to be a marginal HP/HT well with an estimated reservoir temperature of 181°C and a reservoir pressure of 9,971 psi (16.80 lbm/gal) at a depth of 3475-m true vertical depth subsea (TVDSS).
The Middle Isongo sand, intersected by Well IM-3, was the primary gas/ condensate target, consisting of deepwater sands with interbedded shales. The Middle Isongo target package consisted of three reservoir sands, the deepest two of which had not been penetrated in any of the earlier offset wells; this was the primary target of Well IM-5. A secondary target for Well IM-5 was the Intra Isongo, occurring between the Upper Isongo and the Middle Isongo main target.
The well design allowed the 12¼-in.-hole section to be drilled conventionally with statically overbalanced mud weight (MW), but it was impossible to drill the 8½-in. hole without using statically underbalanced MW with managed pressure drilling (MPD). Consequently, it was decided that the 12¼-in. hole would be drilled with MPD so that the crew could become familiar with the procedures and practices that would be needed when the 8½-in.-hole section was drilled. Given the uncertainty in the pore-pressure and fracture-gradient forecast, drilling the 8½-in.-hole section with statically underbalanced MW using MPD was seen as the most efficient means of well construction.
Technology Focus: History Matching and Forecasting (April 2015)
Authors: Emerick Alexandre 
Published: February 2016

Technology Focus
Production forecasting is one of the main tasks of engineers involved in reservoir management. To perform it, they resort to models, which vary from simple decline curves to complex numerical simulations. Regardless of the model’s level of complexity, uncertainty will always exist in the forecasts. Therefore, reservoir engineers devote significant efforts trying to incorporate data in these models (history matching), aiming to mitigate uncertainty and improve the reliability of the predictions.
The reservoir-history-matching literature is quite extensive. The first works on automatic history matching were published in the 1960s. Nowadays, there is a wealth of history-matching methods. As a result, we observe that it is becoming a common industrial practice to generate multiple history-matched models, even for fairly complex problems with thousands of uncertainty variables and a large amount of data. However, we are still far from a definitive solution. Actually, it seems that there will be no single best history-matching technique. Instead, what we may have is the best method for the specific problem. Moreover, there are many challenges that are not completely addressed. In particular, most of the approaches seem overly simplistic to handle complex geology and structural uncertainties. Also, the computational demand for uncertainty quantification remains an issue. Therefore, industry and academia still have much work to do.
Another point I want to mention is that, back in 2009, SPE promoted a forum meeting titled “Getting to Robust Production Forecasts.” This meeting became the startup of a Global Integrated Workshop Series on production forecasting. To date, there have been six meetings; the latest was held this year in Malaysia. These workshops have the ambitious goal of developing a production-forecasting guideline. I think we will hear more about this in the coming years.
The papers summarized in this feature and the ones indicated in the additional-reading list are good examples of recent developments and field applications of history matching and forecasting. I hope you enjoy them. JPT
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 163582 An Ensemble-Based Nonlinear Orthogonal Matching Pursuit Algorithm for Sparse History Matching of Reservoir Models by Ahmed H. Elsheikh, The University of Texas at Austin, et al.
SPE 170622 Integrated Subsurface Uncertainty Study and Application—A Case Study of a Chalk Reservoir, Greater Ekofisk Area, North Sea by H.J. Yu, ConocoPhillips, et al.
SPE 170945 Practical Considerations for Forecasting Production Data in Unconventional Reservoirs—Variable- Pressure Drop Case by P.W. Collins, Texas A&M University, et al.
Production From a Fractured Well With Finite Fracture Conductivity in a Closed Reservoir: An Exact Analytical Solution for Pseudosteady-State Flow
Authors: Chen Kang Ping 
Published: February 2016

SummaryPseudosteady-state (PSS) flow is a dominant time-dependent flow regime during constant-rate production from a finite closed reservoir. For a vertical well with a fully penetrated vertical fracture in a circular drainage area modeled as bounded by a slightly elliptical boundary, Prats et al. (1962) obtained an exact analytical solution for such a flow for the case of infinite fracture conductivity. For finite fracture conductivity, the current method to achieve a PSS solution is to run numerical simulations to long times. This paper extends the work of Prats et al. (1962), and presents the first exact analytical solution for PSS flow for a fully penetrated fractured vertical well with finite fracture conductivity. The exact analytical solution is expressed in terms of elementary functions, and it provides simple expressions for the PSS constant, dimensionless productivity index (PI), and effective wellbore radius. The present work eliminates the need of performing time-consuming numerical simulation for obtaining PSS solution for fractured wells in such a reservoir, and the new analytical solution can be used to generate approximate solutions for reservoirs of other geometrical shapes. The new solution can also be used for fracture-design optimization and production-rate decline analysis.