bluuebunny/crossref_metadata_2025_split huggingface dataset:
Techbits: Subsurface Corrosion Spotlighted at Workshop
Authors: JPT staff _ 
Published: February 2015

Techbits
Corrosion remains a major challenge to maintaining the integrity of infrastructure in oil and gas fields, particularly at the subsurface. A recent SPE Applied Technology Workshop in Abu Dhabi, UAE called "Subsurface Corrosion Risks and Challenges" highlighted critical aspects of subsurface corrosion control, including selection of corrosion-protection methods, improving drilling practices to minimize corrosion, and assessing downhole corrosion-monitoring techniques.
The welcome address by Qasem al-Kayoumi of Zadco highlighted the importance of organizations working together to identify critical subsurface corrosion challenges, share and agree on best practices, and identify the best existing downhole corrosion-mitigation technologies. To understand the technical areas where additional focus is required, networks must be formed between the operators, well engineers, and service providers. Al-Kayoumi said that Zadco has gained valuable subsurface experience by creating a seamless co-operative relationship with other operators. Zadco has also sponsored projects for downhole corrosion-modeling programs.

Materials for Oil and Gas Production
The first technical session of the work-shop highlighted materials used in oil and gas production. Keynote speaker Bijan Kermani of KeyTech opened by stating that hydrocarbons will continue to be the world's principal energy source in the foreseeable future. The expected growth in energy demand will spur increases in production, which will become more multiphase in nature and contain higher percentages of harsh components such as hydrogen sulfide (H2S) and carbon dioxide (CO2). These acid gases in high water-cut production systems present major corrosion concerns.
Therefore, material selection must become more specific to mitigate corrosion, and the impact of corrosion with regards to health, safety, and the environment; capital expenditure; and operational expenditure must receive continued serious consideration. Kermani said that materials selection must be coupled with ‘near-realistic’ corrosion modeling and prediction for optimum integrity assurance.
Zadco's Obadah Al-Sawadi next discussed the principles of corrosion modeling and prediction as they relate to materials selection. He stated that any useful model should be able to accurately predict corrosion rates as operating conditions change and account for actual tubing conditions rather than predict the phenomena at only one set of design conditions. A successful modeling program should also clearly define target corrosion rates to assess whether carbon steel or a corrosion-resistant alloy (CRA) should be employed. Finally Al-Sawadi highlighted several continuing challenges for accurate modeling programs, including obtaining accurate field data, the large number of variables involved and their relevance, and changes in the operating regime.
Low-Damage Massive Hydraulic Fracturing Technique in Tight Gas Formations With High Temperature and High Pressure
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 114303, "The Study and Application of Low-Damage and Massive Hydraulic-Fracturing Technique in Tight Gas Formations With High Temperature and High Pressure," by Lei Qun, Tingxue Jiang, SPE, Xu Yun, SPE, Yunhong Ding, SPE, Yongjun Lu, SPE, Cai Bo, Yuhua Shu, and Yaoyao Duan, PetroChina, prepared for the 2008 SPE Gas Technology Symposium, Calgary, 16-19 June. The paper has not been peer reviewed.
Many tight gas formations in the southern Songliao basin in northeast China have high pressure/high temperature (HP/HT) conditions. However, it is very difficult to conduct successful fracturing treatments in the deep wells (deeper than 4200 m) with temperatures greater than 150°C and pressures greater than 60 MPa. A study was conducted to overcome these difficulties.

Introduction
There are many difficulties related to hydraulic-fracturing design and treatment in tight HP/HT gas formations, including formation fines, initiation and propagation of the hydraulic fracture, selection of a low-damage and highly viscous elastic fluid, selection of a high-strength proppant that is transported easily, and that many fracturing-treatment failures result from early tip screenout. The commonly used fracturing technique included ordinary guar fluid with relative high polymer concentration and high residue content; medium proppant size of 20/40 mesh; a common proppant-pumping schedule such as 180, 360, 540, 720, and then 900 kg/m3; and longer shut-in time (at least 2 hours). Consequently, the post-fracturing production rate was disappointing.

Formation Evaluation
For fracturing design, it is critical to understand the targeted formation in both macro- and microperspectives. Macroparameters include sediment, perforation data, permeability, porosity, thickness, saturations, rock mechanics, in-situ stress magnitude and azimuth, and the distribution of these parameters. Macroparameters may be available from drilling, logging, and well-testing data. Microparameters include mineral components and sensitivities of micropore structure such as pore and throat diameter, along with natural fissures and their distribution. Microparameters may be obtained from test data of core samples in the laboratory.
In fracturing-stimulation design, macroparameters may be used to optimize fracture length, conductivity, and proppant selection, while microparameters are used mainly to choose low-damage fluid additives and determine their mixture, optimize use of 100-mesh proppant or any other solids-loss reducers in case of natural fissures, and optimize the time and velocity of flowing back fracturing fluid in case of stress and velocity sensitivity.
Fusion of Engineering and IT Transforms the E&P Business
Authors: Brule Mike 
Published: February 2015

Management
The case for information technology’s (IT’s) direct value in E&P has been made for technical computing, real-time monitoring, workflow automation, data integration and quality, unified communications and collaboration, data mining, and artificial intelligence (AI) (Marks 2008; Brulé 2009). But few reservoir and production engineers acknowledge the fundamental need for IT in their everyday activities. E&P leadership abets this attitude with unofficial indifference to IT. The isolation of IT from the core E&P business was demonstrated when SPE held two Americas forums simultaneously, one reservoir engineering-oriented and the other IT-oriented (Shillings 2009). The two forums focused on the E&P business themes of “making better decisions” and “maximizing oil recovery,” but there was little interaction between them.
E&P industry biases weigh against IT. IT has been characterized as “too thin” in E&P engineering and integrated operations (IO), and less relevant as digital oilfield (DOF) formulation moves into DOF 2.0 implementation (Holland 2009). One notion is that “E&P data analyses are different and we do more full-physics modeling than in other industries.” Another is that “we have advanced visualization and enough other technologies.” Further submerging IT below other E&P business concerns, decision-makers tend to focus more on where to explore and drill, and less on using IT to standardize and optimize subsequent operations (Mahdavi et al. 2009). Several case studies of companies outside the oil & gas industry show that when executive leadership mandates that IT be part of the company business model, corporate performance is clearly improved (Weill and Ross, 2009). Yet making IT a central part of the E&P business model is still among the “burning issues” of E&P chief information officers (CIOs).
Different Backgrounds
IT’s lack of familiarity is especially evident in modeling and simulation. A grasp of how to model the behavior of oil & gas systems is normally gained through formal training in math, physics, chemistry, engineering, and geoscience. Most IT specialists are unfamiliar with the basic laws of thermo-dynamics and fluid flow, and “bean-up guidelines for sand-control completions.”
The tables turn when engineers transfer to an IT role without any computer-science training. Few engineers are familiar with IT architecture and governance frameworks such as TOGAF, ITIL, and CMMI, and “idempotent capability in cloud patterns.” Without a sound background in data structures, event-driven architecture, or development platforms, engineers may flounder in software and systems development. In IO and DOF 2.0 efforts, the engineer’s lack of an IT background may also lead them to confuse operations monitoring, control, and visualization vs. complex event processing and predictive analytics (Brulé 2009; 2010). To bridge the gaps between engineering and IT, some universities have begun offering a hybrid “digital petroleum engineering degree” with a dose of computer-science courses (Ershaghi et al. 2009).
Choices for LNG FPSOs
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 19884, ’Choices for LNG FPSOs,’ by L.J.F.M. Festen and J.B.P.M. Leo, CB&I Lummus B.V., originally prepared for the 2009 Offshore Technology Conference, Houston, 4-7 May.
An estimated quarter of world gas reserves currently is stranded in offshore gas fields. The energy markets and dwindling oil reserves highlight the necessity to find new ways for offshore gas production. Liquefied-natural-gas (LNG) floating production, storage, and offloading (FPSO) vessels will be required to develop the fields that are too far from market for pipelines or are in extreme water depths. Despite many design studies, technical and economic constraints have prevented LNG FPSOs from being developed as fast as oil FPSOs.
Introduction
More than 20 years of development work has been performed on LNG FPSOs, but apparently there are challenges that have prevented the realization of such a project even with rising gas prices. Both the organization of the project and the actual design of an LNG FPSO are considerably more complicated than those of an oil FPSO. The full-length paper discusses the choices to be made during selection and design of a project on the basis of many years of development work.
Table 1 in the full-length paper lists the main parts of an LNG FPSO where choices have to be made. For an offshore facility, the interdependence of the choices is much stronger than onshore because of the limited plot area on an FPSO.
Selection of Gas Field and Pretreatment
The design of the LNG FPSO begins with the selection of the gas field to be developed and the intended market for the LNG. The higher-heating-value (HHV) specification for the LNG together with the hydrocarbon part of the feed-gas composition determines the natural-gas-liquids (NGLs) separation.
A very rich gas (i.e., high C2, C3, C4, C5+ content) and a market that requires lean LNG will require a pretreatment process that also produces liquefied petroleum gas (LPG) and condensate. The leaner the LNG specification, the more NGLs that have to be separated. When the mol ratio of methane to ethane in the feed gas is lower than 14 to 11, it becomes very difficult to produce a lean LNG specification with HHV less than 1,070 Btu/scf unless ethane is produced as a separate product. Producing a fourth product, liquid ethane, is rather improbable for an FPSO.
Combining Wireline and LWD Borehole-Seismic Data for Drilling an HP/HT Well
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 13083, ’Combining Wireline and LWD Borehole Seismic Data for Drilling an HP/HT Well: A Novel Approach,’ by T.K. Lim, SPE, and Aqil Ahmed, SPE, Schlumberger, and Gunawan Taslim and Muhammad Antonia Gibrata, SPE, Petronas, prepared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December.
An integrated borehole-seismic technique was used to access and mitigate drilling risk on a high-pressure/high-temperature (HP/HT) exploration well offshore Sabah, Malaysia. The approach combined wireline vertical seismic profiling (VSP) with logging-while-drilling (LWD) seismic surveys to predict pore pressure, determine geo-stopping, and obtain high-resolution seismic imaging beyond the well path. This high-resolution image was used to select the sidetrack path. The final rig-source VSP was logged at total depth (TD) to complement the pore-pressure prediction and seismic imaging.
Introduction
Integrating wireline and LWD bore-hole-seismic information for drilling is a new technique in Malaysia. In this approach, borehole-seismic data, which are used conventionally for geologic and geophysical interpretation, have added value for drilling and well planning.
The well, drilled in 2008, is off the coast of Sabah, East Malaysia. The target reservoir, in contrast to most other reservoirs in the region, is deeper, hotter, and at much higher pressures than normal. Pore-pressure ramps and depleted sands in the field had made drilling difficult previously, generating hazardous incidents including stuck and in-hole-lost pipe, fluid losses, and kicks. These incidents had resulted in stopping drilling prematurely, resulting in ultradeep targets remaining unexplored. Studies by the sedimentologist suggested that this overpressure hazard is associated with undercompacted bathyal mudstone, and the well-casing design required accurate prediction.
The well path was designed to avoid the regional fault that could complicate pore-pressure prediction. Existing surface-seismic and distant-well-based velocity control were inadequate for this purpose.
Primary well objectives were the lightly explored, stacked, lowstand Upper Miocene turbidite-reservoir sequences. The deepest of these were expected to be at approximately 4000- to 5000-m sub-sea (SS) depth. The shallow units, which are depleted because of production from other locations, were at approximately 2500- to 4000-m SS depth.
Technology Focus: History Matching and Forecasting (April 2010)
Authors: Romeu Regis Kruel 
Published: February 2015

Technology Focus
“Prediction is very difficult, especially of the future” (Niels Bohr, Danish Physicist, 1885–1962). Indeed, even prediction or modeling of the past is very difficult in reservoir simulation. However, as complex as it is, history matching for model calibration generally is required to generate convincing forecasts. Fortunately, more-productive and -consistent methods are moving from research to application.
The traditional trial-and-error approach for history matching usually is disappointing: too time-consuming and ineffective at the end, depending on the objectives. Consider a reservoir-simulation model calibrated by the usual not-so-bad/not-so-good history matching (easier to consider than to do), and its use for short-term and long-term forecasting. Despite all of the built-in physics, numerical algorithms, geology characterization, etc., the short-term forecast from this model may be worse than just assuming that each well will repeat its current water-cut data next month. This result is because recent production data were only loosely assimilated into the model, whereas these data are of first-order importance to predict next month’s production. For long-term prediction, we notice that standard workflows generally are not good for coupling uncertainty analysis with history matching. A large and representative sample of possible scenarios should be explored to obtain robust long-term forecasts, but this is difficult in practice because of the lack of time, lack of imagination, or lack of method.
Modern history matching tends to be different from traditional methodology in many ways: numerical optimization instead of manual trial and error, multiple-scenario exploration instead of single-scenario exploitation, or geological consistency instead of ad hoc artifices. Three approaches have been developed with several variants and hybridization: gradient-based methods; stochastic-global-optimization methods; and—the most in vogue—data-assimilation methods, such as ensemble Kalman filter. Besides fast computers and advanced software, human-expert intervention will continue to be essential. Continued training is of uppermost importance. Keep track of the literature.
History Matching and Forecasting additional reading available at OnePetro: www.onepetro.org
SPE 119030 • “Stochastic History Matching of a Deepwater Turbidite Reservoir” by Faruk O. Alpak, SPE, Shell, et al.
SPE 125512 • “Data Assimilation Coupled to Evolutionary Algorithms—A Case Example in History Matching” by Ralf Schulze-Riegert, SPT Group, et al.
SPE 118879 • “History Matching Using a Hierarchical Stochastic Model With the Ensemble Kalman Filter: A Field Case Study” by Yanfen Zhang, University of Oklahoma, et al.
Hybrid Ensemble Kalman Filter With Coarse-Scale Constraint for Nonlinear Dynamics
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 124826, ’A Hybrid Ensemble Kalman Filter With Coarse-Scale Constraint for Nonlinear Dynamics,’ by Shingo Watanabe, SPE, Akhil Datta-Gupta, SPE, and Yalchin Efendiev, SPE, Texas A&M University, and Deepak Devegowda, SPE, University of Oklahoma, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October.
Interest in ensemble Kalman filters (EnKFs) is driven by the need for continuous reservoir-model updating and uncertainty assessments based on dynamic data. The EnKF approach relies on sample-based statistics derived from an ensemble of reservoir-model realizations. Sampling error in these statistics, particularly with the use of modest ensemble sizes, can degrade EnKF performance severely, leading to parameter overshoots and filter divergence. The proposed hybrid-multiscale EnKF improved operational-data assimilation and helped overcome many limitations associated with the classical EnKF implementation.
Introduction
A primary motivation for history matching is to construct reliable predictive models and then to quantify the uncertainties in forecasting. Traditional history matching applies local and regional changes by use of multipliers to reservoir properties to calibrate the reservoir model with production data. However, this approach often creates artificial discontinuities that lessen geologic realism in the updated model. The manpower and time required to achieve a satisfactory history match render the manual process inefficient for assessing multiple-model realizations. Automated methods that use inverse theory or stochastic approaches to minimize appropriately defined misfit functions have received increased attention along with development of robust history-matching algorithms and enhancements in computational capabilities.
With modern field-monitoring technology, such as permanent well monitors and intelligent-completion technology, production data often are incorporated into the reservoir model upon availability. Recognizing under-lying uncertainties in the geologic model, it is desirable to generate a suite of plausible model realizations rather than a single best-history-matched model. The EnKF combines these capabilities for the purposes of reservoir characterization and uncertainty assessment. In the EnKF framework, an ensemble of model realizations is updated progressively as the data become available by use of an assimilation sequence that contains a forecast step that propagates the ensemble forward in time and an update step that modifies the reservoir variables to match the current observation.
Macondo Blowout Spawns a Pair of Containment Firms in Gulf of Mexico
Authors: Rassenfoss Stephen 
Published: February 2015

A year after the blowout that destroyed the Deepwater Horizon platform and triggered an oil spill that lasted for months, two companies with strong ties to the effort that shut off that well are competing to be the containment firm of choice for deepwater operators in the US Gulf of Mexico (GOM)—Marine Well Containment Corporation (MWCC) and Helix Well Containment Group. In mid-February, MWCC rolled out its interim containment system built around a mix of new equipment and components used by BP last year to shut down the Macondo well. The venture was created in July 2010 by ExxonMobil with Chevron, ConocoPhillips, and Shell. In September BP joined, contributing a variety of hardware, including a manifold, flexible pipe, a riser assembly, and containment devices, including the “top hat.”
The Helix Fast Response System is built around the two vessels that became a familiar site in the aerial photos of the fleet of boats used to choke off the output from Macondo—the Q4000 which served as a production platform and the Helix Producer I that processed the crude and offloaded it to tankers.
At the end of February, Bureau of Ocean Energy Management, Regulation, and Environment (BOEMRE) issued the first deepwater drilling permit. It gave Noble Energy permission to complete a well on its Santiago prospect that it had to stop drilling in June 2010, because of the moratorium after the Macondo blowout. It named Helix as its well containment provider.
Having approved deepwater emergency response options is an essential part of getting approval for a deepwater drilling permit application. A regulation from BOEMRE—NTL 2010-N10—requires anyone who wants to drill to provide detailed information on how it could react quickly and effectively in the event of a blowout.
Compliance requires more than naming an approved provider. Documentation running more than a thousand pages long answers many of the questions that could speed emergency responses—from detailed descriptions of the well hardware to well design integrity studies intended to help answer a question that slowed the Macondo response—can the well stand up to the pressure if it is capped?
In creating their systems, both companies followed a similar approach: relying on well-established, reliable designs, components, and technology, and working closely with regulators to be sure the systems complied with their reading of the new rules.
Even after BOEMRE approves a system, operators seeking drilling permits will still need to convince regulators that the emergency response company has the capability to deal with a worst-case discharge from that well, said Ken Arnold, a member of SPE’s GOM Incident Response Task Force. The task force held a workshop with industry and academic experts to study the rule. It created a document offering guidelines based on how to estimate the dimensions of an incident “where everything in the world has to go wrong.”