bluuebunny/crossref_metadata_2025_split huggingface dataset:
Beyond Beta Factors: A Model for Darcy, Forchheimer, and Trans- Forchheimer Flow in Porous Media
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 89325, "Beyond Beta Factors: A Complete Model for Darcy, Forchheimer, and Trans-Forchheimer Flow in Porous Media," by R.D. Barree, SPE, Barree & Assocs., and M.W. Conway, SPE, Stim-Lab Inc., prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.
Darcy’s law is valid in a relatively small velocity region. Forchheimer’s equation, with its inertial-flow parameter, β, is used as an extension of Darcy’s law beyond the linear-flow region. This “trans-Darcy” flow is important in hydraulic-fracture-conductivity calculations, in which flow velocities in the proppant pack are much higher than in the surrounding reservoir. The computation and presentation of β values as functions of closure stress and permeability are important for proppant selection and fracture-treatment design. A single equation was developed that describes the relationship between rate and potential gradient for porous-media flow over the entire range of values of Reynolds number, NRe.

Darcy's Law
From Darcy’s observations of experiments on flow rate, he concluded that flow rate varied in proportion to the imposed head and inversely to the height of the sand pack. The flow rate could be related to the imposed head through a linear proportionality involving a constant, k, which is a coefficient dependent on the permeability of the sand layer. The concept of a constant “Darcy” permeability, suggesting a linear relationship between flow rate and potential gradient, was accepted until empirical observations of flow rate at higher differential pressures confirmed that the relationship between flow rate and potential gradient becomes nonlinear at sufficiently high velocity.
Overview: Production Operations (March 2005)
Authors: Rogers John D. 
Published: February 2015

There has been much debate about when individual countries and the world will peak in oil and gas production. It has been reported that brownfields accounted for less than 20% of the world’s oil production in 1982, but nearly 45% in 2002. A simple linear extrapolation suggests that by 2012, one-half of the world’s oil production will come from fields where production rates are declining. Generally, as a field matures and proceeds on its downward economic spiral, water-related problems escalate. This year, more than 40% of the nearly 100 papers reviewed for this feature were related to scaling and treatment. Many of these papers were from the Middle East, North Sea, and South American provinces. Implementation of innovative methods is needed to arrest declines and increase recovery factors.
Production optimization has two main objectives. One is to increase maximum production while minimizing capital expenses. The second is to reduce the inevitable production decline of a field. One interesting case is that of the Sacroc field in west Texas. This field has produced under an enhanced-oil-recovery project for more than 30 years with a high decline rate. After infrastructure rejuvenation, new data-acquisition processes, innovative interpretation, and sound engineering management, considerable cost savings were accomplished in recent years, significantly curtailing the decline.
One of the primary factors limiting production performance has been the lack of timely and reliable data analysis. A recent paper (SPE 87121) suggested that timely, reliable tools and training in the analysis of drilling data could be of great benefit to cost-effective drilling. The management of reliable real-time data from all segments of the oil and gas exploration and production process becomes a workflow-management challenge to make effective, relevant, and timely decisions.
The uptake of credible emerging hardware advances technology and enhances the overall industry experience and learning curve. The Natl. Petroleum Council’s 2003 report suggested that higher prices and difficult resources should catalyze increased efforts in research, development, and application of technologies. This will be critical if the recovery factor of the inevitable brownfields is to be economically improved.
Additional Production Operations Technical Papers
Available at the SPE eLibrary: www.spe.org
SPE 90430 - Successful Implementation of Resurgent Relative-Permeability-Modifier Technology in Well Treatments Requires Realistic Expectations
SPE 88543 - Impact of Dynamic Simulation on Establishing Watercut Limits for Well Kickoff
SPE 89837 - Cleanup of Water Blocks in Depleted Low-Permeability Reservoirs
SPE 91041 - Web-Based Hosting of Multiassets and Multiusers: Production Workflows
SPE 90792 - Integrated Process Improves Production of the Almond Formation in the Wamsutter Field, Wyoming: A Low-Permeability Case Study of 5 Years of Continuous Improvement in Well Performance
The Effect of Thief-Zone Identification and Shutoff on Water Production in the Nimr Field
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 91665, "Impact of Thief-Zone Identification and Shutoff on Water Production in the Nimr Field," by Richard S. Medeiros, SPE, Petroleum Development Oman; Deepankar Biswas, SPE, DeGolyer and MacNaughton; and P.V. Suryanarayana, SPE, Blade Energy Partners, prepared for the 2004 SPE/IADC Underbalanced Technology Conference and Exhibition, Houston, 11-12 October.
The full-length paper describes ongoing efforts to improve the performance of Nimr wells by identifying and shutting off thief zones and summarizes the results to date. Underbalanced drilling (UBD) data have shown that rogue fractures and bypass zones play a key role in the movement of water through Nimr reservoirs. UBD was used to identify nonmatrix water-bearing features and shut them off by use of different shutoff techniques, including a new selective shutoff completion tool.

Introduction
The Nimr field in southern Oman is a group of six fields, most of which are mature oil fields operated by Petroleum Development Oman (PDO). The fields A, B, E1, E2, and G produce medium-gravity viscous oil under strong bot-tom waterdrive. These fields contain more than two billion bbl STO initially in place and have been on production since the mid-1980s. Initial development was by vertical wells, but since the mid-1990s development primarily has been by horizontal wells. Production is from a combination of Cambrian aeolian and carboniferous glacial sediments. Reservoir het-erogeneity is high, particularly in the glacial Al Khlata reservoirs. Combined production from the Nimr fields accounts for more than 10% of current PDO oil production and is produced from approximately 500 active wells at an average 93% water cut. A combination of unstable displacement, strong aquifer drive, complex geological settings, and nonmatrix permeability events has resulted in unpredictable new-well performance with progressively higher initial water cuts. In this respect, Nimr presents the typical problems of a mature field—that of water movement and its effect on sweep and recovery. One of the key developmental strategies has to be identification and mitigation of water movement, thus reducing the amount of water produced and improving net oil production.
UBD. UBD began in the Nimr A field in 2002. UBD typically is used to increase well productivity by eliminating drilling-induced formation damage for faster drilling/penetration rates. Although UBD was initially used in Nimr for these objectives, its long-term value has been its reservoir-characterization (RC) data. Nimr is one of the unique fields where the RC benefits of UBD have driven its continued use in the field. The investigations carried out using UBD RC data in 2002 and 2003 have resulted in the evaluation and exploitation of two significant opportunities in addition to other large, longer-term opportunities currently being developed.
Transient Behavior of Annular-Pressure Buildup in HP/HT Wells
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 88735, "Transient Behavior of Annular-Pressure Buildup in HP/HT Wells," by P. Oudeman, SPE, and M. Kerem, SPE, Shell Intl. E&P, prepared for the 2004 SPE Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, 10-13 October.
Pressure buildup resulting from the thermal expansion of fluid in the sealed annuli of high-pressure/high-temperature (HP/HT) wells can have serious consequences such as casing failure or tubing collapse. To determine if mitigation was required for an HP/HT development, annular pressures in an appraisal well were studied with a dedicated field test that consisted of running a pressure/temperature memory gauge in a casing/casing annulus of a well and testing the well several times during a 3-month period.

Introduction
Pressure buildup in tubing/casing or casing/casing annuli is usually undesirable. Although casing design should consider high pressures at the casinghead that could result from leakage or thermal expansion of annular fluids, high pressure differences always present the risk of casing burst or collapse at weak points. Most operating companies have some form of annular-pressure management for onshore and platform wells that calls for bleeding off pressure through the wellhead once a predetermined pressure is reached.
Such schemes cannot be used in subsea wells because these wells usually will not be equipped with the option to bleed off the annular pressure and to divert the released liquids. In HP/HT wells, the high temperature in the well during prolonged production periods aggravates pressure buildup in the annuli because the thermal expansion of liquids tends to increase at higher temperatures. Because casing-string design must consider those pressures, accurate prediction of annular-pressure buildup is important.
Theoretical models to predict thermal annular-pressure buildup have been proposed by a number of authors. Usually, these models take into account fluid thermal expansion, ballooning and compression of the casings, annular fluid leakoff, and formation fluid influx.
In a first attempt to validate the theoretical models, a field test was set up to study pressure development in the casing/casing annulus of an offshore platform well. However, in this particular well, the inner (production) casing was not cemented into the shoe of the outer casing. The test demonstrated that in this case, annular-fluid leakoff completely dominated the pressure buildup. The test did not allow any conclusion to be drawn about the overall validity of the theoretical models for pressure buildup. Hence, a second test in the sealed annulus of an offshore HP/HT gas well was planned and executed.
Management: Uncertainty and Volatility in Today's Energy System: Stability, Security, and Sustainability Through Mutual Interdependence
Authors: Bozon Ivo 
Published: February 2015

Many have argued that the oil and gas industry has entered a final era of very scarce resources—a new equilibrium of bottlenecked supply, steep cost curves, continued demand growth, and, as a result, continued very high price levels (Fig. 1). It is hard to believe, however, that resources are the constraint, given the enormous potential still available, including currently known and booked reserves, the increased scope for recovery of existing fields with new technologies, further potential discoveries, and the new frontier of vast oil sands and oil shales reserves that are in the money at cur-rent oil prices. In essence, according to the majority of the industry's research, we have enough resources left to sustain current production levels for between 40 and 60 more years.
Indeed, the core challenge is not one of resources but one of putting reserves into production and delivering energy to markets. This is evident already today. The expected near-term growth in production is barely enough to meet rising demand, let alone restore the spare production capacity to historic levels of 3–5 million BOPD, which helped maintain stable price levels in the past decades.
Thanks to this tight market, the outlook for demand and supply is as uncertain and volatile as it was in 1998, when oil was U.S. $10 a barrel, the industry's other big period of upheaval in the last quarter century. Moreover, this level of uncertainty is likely to continue in the coming decade. In particular, there are two specific time periods in which the current balance of supply and demand could shift dramatically: in the short term (over the next 3 years) and in the long term (after 2015).

Short-Term Demand
In contrast to the 1970s, when power generation was still a significant component of demand, today transportation fuels dominate. So far, high prices have not reduced consumers' thirst for transportation fuels, and total demand has remained more robust than in the earlier periods of price increases.
However, the evidence is growing every week that demand will begin to fall in the near term. Recent increases in government-regulated fuel prices sparked large drops in demand for oil products in Indonesia (30%) and Thailand (20%). China and other countries with regulated fuel prices are considering similar moves. In the Organisation for Economic Co-operation and Development (OECD) countries, the evidence is less clear cut. Nevertheless, the transport sectors in the U.S. and Europe exhibit early signs of a slowdown in demand growth (e.g., the slowdown in U.S. sport-utility vehicle sales, the shift to lower-priced petrol grades in Germany, and the slowdown in diesel and especially gasoline sales growth in 2005 in Europe).
Overview: Hydraulic Fracturing (March 2007)
Authors: Chipperfield Simon 
Published: February 2015

Hydraulic fracturing is at a crossroads.
Industry is more interested in this technology than ever before, as evidenced by the explosion of SPE hydraulic-fracturing papers over the last 30 years (from 38 in 1975 to more than 500 in 2005). But who is doing the R&D? Ideally, service companies, operators, consultants, universities, and government bodies would do this equally. The priorities of any one group would never dominate, and a healthy division would exist between technology pull (from industry) and technology push (from academia).
In an effort to better understand who is driving new hydraulic-fracturing technology, a group of hydraulic-fracturing papers in SPE's eLibrary was studied by reviewing the affiliation of SPE primary authors for 1975 vs. 2005. (The search phrase "hydraulic fracturing" was used with an average of 40% of the papers reviewed in each year.) It was determined that technical leadership has changed with time, with a reduction in primary authorship by operators and universities/government bodies (from 40 to 25% and 37 to 25%, respectively) and a corresponding increase by service companies (from 20 to 39%). This trend also was observed in the broader oil industry (Lovendahl 2003) and in the scientific community on an international level (Rapoport 2006).
The reasons for this shift in technology leadership are clear. Many operator R&D programs have declined or have been deemed noncore and completely shut down. Many government bodies are receiving less federal support and are forced to rely on increasingly limited industry cooperative funding (Lovendahl 2003). The result is that most R&D is performed by service companies. This trend could result in hydraulic-fracturing innovation having a bias toward small-step improvement, rather than revolutionary technologies.
Keeping hydraulic-fracturing R&D active is a multifaceted challenge. Hydraulic fracturing is at the highest demand ever. R&D from the full range of industry groups and academia is essential for significant technical and commercial advancements to continue.
Hydraulic Fracturing additional reading available at the SPE eLibrary: www.spe.org
SPE 99428 "A New Approach to Hydraulic-Fracturing Modeling—Fully Coupled With Geomechanical and Reservoir Simulation" by L. Ji, SPE, U. of Calgary, et al.
SPE 102326 "New Results Improve Fracture-Cleanup Characterization and Damage Mitigation" by J.A. Ayoub, SPE, Schlumberger, et al.
SPE 106052 "Pinpoint Fracturing in Challenging Formations" by K.J. Beatty, SPE, Santos Ltd., et al.
SPE 103591 "Use of Extremely High Time-Resolution Production Data To Characterize Hydraulic-Fracture Properties" by J.W. Crafton, SPE, Performance Sciences Inc., et al.
Effect of Non-Darcy Flow on Well Productivity of a Hydraulically Fractured Gas-Condensate Well
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 103025, "Effect of Non- Darcy Flow on Well Productivity of a Hydraulically Fractured Gas-Condensate Well," by J. Mohan, SPE, G.A. Pope, SPE, and M.M. Sharma, SPE, U. of Texas at Austin, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.
Hydraulic fracturing is a common method used to improve the productivity of gas-condensate wells. Previous simulation studies have predicted much larger increases in well productivity than observed in the field. This study showed the large effects of non-Darcy flow and condensate accumulation on the productivity of a hydraulically fractured gas-condensate well.

Introduction
A significant decline in the productivity of gas-condensate wells is caused by a phenomenon called condensate blocking. Pressure gradients resulting from fluid flow in the reservoir are greatest near the well. As the pressure drops below the dewpoint pressure, liquid condenses and the condensate accumulates near the well. This buildup of condensate is referred to as a condensate bank. The condensate continues to accumulate until a steady-state two-phase flow of condensate and gas is achieved.
Modeling hydraulically fractured gas-condensate wells requires taking into account non-Darcy flow. Gas velocity inside the fracture is three to four orders of magnitude higher than that in the matrix. Use of Darcy's law to model this flow can overestimate the productivity improvement. Therefore, it is necessary to use Forchheimer's equation to model this flow with an appropriate non-Darcy coefficient that takes into account the gas relative permeability and water saturation.
Previous simulation studies investigated the effects of well spacing and fracture length on well productivity in low-permeability gas reservoirs. It was shown that the most important parameters for determining the optimum fracture length are the formation permeability and the initial gas-in-place volume. For high-permeability reservoirs, short fractures and large well spacing provide the optimum profit, whereas for tight gas reservoirs, long hydraulic fractures and close well spacing are required to optimize profit from the reservoir.
The near-well condensate buildup reduces the productivity of a well by 50% or more. The loss in total production can be 40 to 80%. Laboratory data have shown a reduction of 91 to 97% in 2- to 5-md limestone cores and 95 to 98% in 246- to 378-md sandstone cores. The presence of water worsened the productivity loss.

Compositional-Simulation Study
A commercial equation-of-state com-positional simulator was used for this study. The reservoir is homogeneous, with a uniform porosity of 20% and a uniform permeability of 1 md. It has a net-/gross-reservoir ratio of 0.5. The reservoir dimensions are 5,000 ft wide by 5,000 ft long by 57 ft thick. The fracture permeability is 7,000 md.
Techbits: Seismic-While-Drilling Technology Takes ETW Spotlight
Authors: Moon Ted 
Published: February 2015

Techbits
While Seismic-While-Drilling (SWD) methods have been investigated for nearly 30 years as a complete, real-time alternative to conventional vertical-seismic-profiling (VSP) techniques, the industry has yet to accept it beyond a rather narrow scope. Expanding this scope was the focus of a recent SPE Emerging Technology Workshop (ETW) held in League City, Texas.
SWD technology, until recently primarily referred to as drill-bit (DB) seismic, began as a method to detect the natural vibration from the end of the drill bit by means of surface geophones, enabling geophysicists and drillers to use these data in real time to optimize drilling efficiency, predict pore pressures ahead of the bit, and verify reservoir models.
This technique has been eclipsed by another method, particularly for deepwater offshore drilling applications, which is based on traditional wireline methods that use a standard offshore air-gun seismic source at the surface with suitable receivers or sensors in a downhole tool. This, together with recording and processing capabilities, is part of an enhanced logging-while-drilling (LWD) tool.
Nonetheless, proponents of DB/SWD technology believe the technique has untapped potential in certain applications. The ETW was seen as the ideal forum in which to discuss this. ETWs are interactive events designed to give participants a field's-eye view of new technologies and to expedite the adoption of these technologies by publicizing their initial successes as they move from laboratory to field.
Andy Hawthorn of Schlumberger helped organize the League City event. "When I got involved, the entire focus was on theory and processing of DB seismic. But because there are still so many limitations with it, we had to include the LWD seismic [LWD/SWD], which has replaced it more successfully on an economic basis."

Open Dialogue, Collaboration Promoted
According to SWD ETW Chairperson Bob Radtke of Technology International, the workshop's open format encouraged lively discussion and debate on the future of the technology. "We had presentations describing the current state of the art, as well as detailed sections on surface source, downhole source, emerging technologies, and case histories," Radtke said. "In addition, this workshop was unique, in that we had a special keynote speaker, Nansen Saleri."
Saleri, manager of Reservoir Management, Saudi Aramco, and a 1991 SPE Distinguished Lecturer, delivered an address titled "The Technology Factor: How It's Changing Upstream Performance." His talk described how the SWD method would be useful for increasing understanding of reservoirs in the Middle East and elsewhere, and indicated that significant producers may be ready to give this technology extensive use.
Another special feature of the ETW was the presentation of two "Legends of SWD" awards to Bruce Marion and James Rector for their 1991 demonstration of the first successful use of drill-bit reverse VSP employing drill-bit-correlated data.