Headquartered in Houston, Texas, Newfield Exploration is an independent company that specializes in the exploration and production of crude oil and natural gas. Its operations in the United States include the Mid-Continent region of Oklahoma and northern Texas, along the Rocky Mountains, southern and coastal Texas, the Gulf of Mexico, and recently in Pennsylvania along the Appalachia Mountains. Newfield also operates internationally through numerous sites offshore of Malaysia and China. By the end of 2009, total proved reserves were 3.6 trillion cubic feet equivalent with approximately 85% of those reserves being located onshore of the U.S. Newfield's present base is estimated to be about 70% natural gas. Today, Newfield has an enterprise value of more than $8.5 billion. Wikipedia.
Krembs M.,Newfield Exploration |
Cort T.,Yale University
Society of Petroleum Engineers - SPE E and P Health, Safety, Security and Environmental Conference - Americas 2015 | Year: 2015
Materiality is a fundamental principle in sustainability and corporate social responsibility (CSR) to determine those issues that are significant enough to companies, investors and other stakeholders to warrant investment, management and disclosure. Exploration and Production (E&P) companies are at various stages of development in the application of materiality tools to support non-financial reporting. This paper describes background on this developing area of practice and a practical approach to materiality taken by one company in the E&P sector. Specifically, we provide first-hand knowledge and guidance for developing a materiality process that adheres to company risk assessment principles, investor and community expectations, and company values and commitments. The approach also integrates mechanisms to incorporate external expert feedback and criteria from leading standards for disclosure such as the Global Reporting Initiative (GRI) G4 Guidelines and the Sustainability Accounting Standards Board (SASB) E&P sustainability accounting standard. Copyright 2015, Society of Petroleum Engineers.
Taylor J.,Noble Energy Inc. |
Taylor J.,Devon Energy |
Fishburn T.,Apache Corporation |
Fishburn T.,Devon Energy |
And 3 more authors.
Geofluids | Year: 2011
Some of the most active and high profile hydrocarbon plays currently being explored and developed around the world lie below a complex salt canopy. Accurate predrill prediction of sub-salt pore and fracture pressures is technically challenging, yet remains critical for mitigating drilling risk and reducing exploration and development costs. The objective of this paper is to highlight how 3-D velocity modeling methodologies can be applied to accurately predict sub-salt geopressures. An example data set from the Lower Tertiary trend of deep water Gulf of Mexico is utilized to demonstrate the key data requirements and earth modeling procedures, and to compare predicted results with postwell drilling reports and measured well data. Central to this approach is a 3-D layered earth model. It is the basis for cross-discipline data integration and provides an ideal platform for well property interpolation, velocity-density-pressure transformations, characterization of geomechanical rock properties, multiwell planning, and drilling risk assessment. Although the main goal of the work is accurate predrill predictions of both pore pressure and fracture pressure for improved well design, these multi-attribute models also provide superior depth prognoses and can be utilized for hydrocarbon column height assessment and seal breach risking, as well as for lithological discrimination. Furthermore, model properties can be incorporated into geomechanical models for detailed wellbore stability analysis. By adopting an earth-model centric workflow, more reliable and robust predrill geopressure predictions have resulted. This has had a positive impact on well design efficiencies and minimized drilling downtime arising from well control events. © 2011 Blackwell Publishing Ltd.
Tipton D.S.,Newfield Exploration
SPE Produced Water Handling and Management Symposium 2015 | Year: 2015
Water is the most common and heavily used fluid in the petroleum industry. It is produced along with oil and gas from nearly every well. Fresh water is used as a base fluid in production, drilling and completion operations. Produced water is primarily handled in three ways: As a base fluid in hydraulic fracturing, for pressure maintenance in secondary or tertiary recovery projects, or for disposal into salt-water injection wells. Hydraulic fracturing uses more water than any other process in the drilling and completion of unconventional wells. An easy way to think of the need for water is: No water, No fracturing, No oil or gas resource play. This paper's focus is on how Newfield Exploration Company approached the design and installation of an infrastructure system for the procurement, transportation, storage, reuse and disposal of water for hydraulic fracturing and associated operations in its Cana Woodford Shale Play. Newfield's Cana Woodford Shale Play covers over 275,000 net acres in central Oklahoma running from Elmore City in the southeast to Watonga in the northwest. When Newfield started on its new venture in the Cana Woodford, the existing infrastructure in the area was not capable of supporting its planned drilling and completion program nor the resulting production and water disposal requirements. To accommodate the exploratory drilling and completion plan, Newfield would install discrete water management systems for each well, which would include (1) sourcing water, (2) constructing frac pits, (3) transporting water to the storage pits in sufficient quantity, and (4) transferring water from the storage pits to well location to support the completions. These one-well water management systems were a necessity for the exploratory drilling program; however, as Newfield shifted to infill drilling and field development, it sought to install a more efficient, fully integrated water management infrastructure that would reduce trucking, make more efficient use of storage space for water, provide broader access to geographically dispersed water resources, and allow for the recycling of produced water as a hydraulic fracturing fluid. Newfield forged new relationships with landowners as a part of establishing operations in the region. Landowner agreements were required to construct pads, obtain right-of-ways to lay water transport pipelines, and build frac pits and other facilities. Several landowners were instrumental in helping our water management team identify water sources in the Cana Woodford play especially in light of the ongoing drought in Oklahoma. ©2015, Society of Petroleum Engineers.
Lyons R.P.,Syracuse University |
Scholz C.A.,Syracuse University |
Buoniconti M.R.,Chevron |
Martin M.R.,Newfield Exploration
Palaeogeography, Palaeoclimatology, Palaeoecology | Year: 2011
Lake Malawi contains a long continuous sedimentary record of climate change in the southern hemisphere African tropics. We develop a stratigraphic framework of this basin over the last ~. 150 ka by integrating several vintages of seismic-reflection data with recently acquired drill cores. In the seismic-reflection data set, we document three lake-level cycles where progradational delta seismic facies and erosional truncation surfaces mark the basal boundary of each sequence. The clinoform packages and their down-dip, time-equivalent surfaces can be mapped throughout each basin, where each major lowstand surface was followed by a transgression and highstand. On several occasions, lake level dropped as much as 500 m below present lake level (BPLL) in the North Basin and 550 m BPLL in the Central Basin, resulting in a 97% reduction of water volume and 89% reduction of water surface area relative to modern conditions. Evidence for these lake-level fluctuations in the drill cores includes major changes in saturated bulk density, natural gamma ray values, and total organic carbon. During lowstands, density values doubled, while total organic carbon values dropped from ~. 5% to 0.2%. Coarse-grained sediment and organic matter flux into the basin were higher during transgressions, when precipitation, runoff, sediment supply, and nutrient input were high. This sedimentation pattern is also observed in seismic-reflection profiles, where coarse-grained seismic facies occur at the bases of sequences, and in the drill-core data where the highest total organic carbon values are observed immediately above lowstand surfaces. © 2009 Elsevier B.V.
Jones R.S.,Newfield Exploration |
Pownall B.,Newfield Exploration |
Franke J.,Newfield Exploration
Society of Petroleum Engineers - SPE/AAPG/SEG Unconventional Resources Technology Conference | Year: 2016
This paper presents a practical method to estimate initial reservoir pressure from early flowback data in fracturestimulated horizontal wells. It is based on estimating flowing bottomhole pressure (pwf) near the time of first hydrocarbon production, while the well is flowing back frac load. The method is important because of the difficulty in measuring initial reservoir pressure in extremely low-permeability unconventional reservoirs. It requires no special instrumentation, and no modifications to flowback procedures (as long as pwf reduction is gradual). Pressures and rates measured hourly at the surface, along with fluid properties and wellbore configuration, are all that is needed. Field examples show the hourly pwf behavior from the beginning of flowback (100% water) to the appearance of first oil or gas, through increasing oil and gas rates as cleanup progresses. Calculated pwf starts out above reservoir pressure due to "frac charge", falls until it levels out or increases near the time of first hydrocarbon production, then declines. The flattening of calculated pwf prior to first measurable hydrocarbon production provides an estimate of initial reservoir pressure. Examples are from horizontal oil and gas wells in the Woodford and Meramec formations of the Anadarko Basin in Oklahoma. The accuracy of calculating pwf from surface data is high while the well is flowing 100% water; this period is relied on to estimate reservoir pressure. Once measurable hydrocarbons are reported, multiphase flow correlations are used. Estimated values of pwf from correlations are compared with measured values from flowing gradient surveys, showing acceptable error for both oil and gas wells in the subject area. The applicability of other techniques for estimating initial reservoir pressure in unconventional reservoirs is discussed. The importance of accurate initial reservoir pressure and pwf over time are discussed, along with the use of such data in play assessment and development. An example shows how trends in reservoir pressure over a large Woodford play were identified by applying the technique on every well. The method and examples described herein will enable engineers to recognize typical profiles of wellhead pressure and pwf during flowback, and to estimate initial reservoir pressure in wells where direct measurement is difficult or impossible. Copyright 2014, Unconventional Resources Technology Conference (URTeC).