Dorn, Philip B. (Shell Global Solutions) | Rabke, Stephen P. (M-I SWACO) | Glickman, Andrew H. (ChevronTexaco Energy Research) | Louallen, Jeff (Shell Global Solutions) | Nguyen, Khai (M-I SWACO) | MacGregor, Robert (Halliburton Energy Services Group) | Candler, John E. (M-I SWACO) | Wong, Diana C.L. (Shell Global Solutions) | Hood, Cheryl Ann (Baker Hughes Drilling Fluids) | Hall, John A. (Halliburton Energy Services Group) | Purcell, Thomas W. (American Petroleum Institute)
The offshore oil and gas industry has moved toward the use of synthetic-based drilling fluids (SBF), changing potential exposure scenarios for discharged cuttings when compared to those of water-based drilling fluids (WBF). Unlike WBF, SBF sorbs predominately to particles in the cuttings and are not dispersed extensively into the water column, therefore, a sediment toxicity test was required by the US Environmental Protection Agency (US EPA) in addition to the existing water column test to define a best available technology (BAT) limit. Inclusion of a sediment toxicity test for NPDES compliance was precedent setting and unique. In order to fulfill the US EPA requirements, an inter-industry research group worked with EPA to develop a suitable test that met the technology-based discharge standard.Toxicity of discharged field drilling fluid is compared to a reference SBF (C1618 internal olefin) and, for compliance, the ratio of the reference drilling fluid median lethal concentration (LC) to the field mud LC must be =1.0.Prior to its use, there were concerns that false positive results could cause incorrectly identified non-compliance events, limiting the use of SBF technology. Consequently, initial application allowed the use of a variability (K) factor in determining the ratio. After initiation as a compliance test, research was continued to reduce test variability and minimize false positives. That research included: 1) analysis of NPDES compliance data (500+ tests), 2) two inter-laboratory testing programs, 3) analysis of reference fluid data from one commercial laboratory, and 4) refinements to test sediment type and animal health. The results of these efforts to date are reviewed in this paper and are used to identify potential improvements in the application of the test as a regulatory tool.
The environmental safety of industrial activities in the US has evolved as a self-monitoring system with permittees testing and reporting compliance results to regulatory authorities.For offshore operations in the oil and gas extraction industry, protection of marine resources is of paramount importance. In the US, resources can be protected through the use of water-quality-based and technology-based compliance limits for operations. Water-quality-based limits follow risk assessment principles, where estimated or measured exposures in the environment may be measured against numerical standards such as a chemical indicator (e.g., zinc, cadmium, mercury). Technology-based limits reflect Best Available or Practicable Technology (BAT) for a specific purpose or industrial sector. These limits are derived from the best possible performance of a given technology for controlling possible environmental impacts. In contrast to individual chemical or single parameter measurements, toxicity tests have been increasingly used in both water-quality-based and technology-based compliance in other industries and regulatory jurisdictions to reflect an integration of the "total environment" in assessing the combined potential effects of substances, such as effluents and wastes. Laboratory toxicity tests using an effluent or waste sample essentially integrate the environmental exposures from all potential toxicants or environmental conditions.
However, as with any assessment endpoint for such a test, there is inherent variation with the results, such that "bright line" limitations may result in false positive and negative results, the former leading to violations, and the latter to potential environmental damage. A false positive is an incorrect judgment that the result is not in compliance when it is; a false negative is judging the outcome to be in compliance when in fact it is not. Both present challenges to standardizing testing methods to limit variation due to chance. The introduction or development of such methods therefore requires interaboratory and intralaboratory testing programs to calibrate the variability, a goal that has often been accomplished for water-based drilling fluids and effluents.
According to the OSHA database for the period from 1997 through 2003, one fatality occurred every 10 days in the U.S. upstream (E&P) oil and gas industry.To determine trends and provide insights into the safety failures, as well as potential interventions to eliminate the high frequency of fatal incidents, the seven years of OSHA data were reviewed.This data encompasses over 250 fatalities from the four principal SIC categories that comprise the onshore upstream oil & gas exploration and production industry.Data were sorted initially by region, well drilling or field servicing, rig type, and event.Further analysis was conducted by a diverse team of industry professionals, including representatives from operating companies, well drilling and servicing companies, and industry trade associations.Particular focus was directed at accident type, equipment type and well site location in an attempt to identify causal factors from the limited incident descriptions contained in the OSHA database.
The resulting analysis showed nearly half of all fatalities (47%) resulted from "struck by" incidents; fires and explosions accounted for 16% while falls from heights accounted for another 14% of the fatalities. Fatality incident rates from year to year were strongly correlated to overall upstream industry activity level as represented by the U.S. rig count.
This fatality data review provides oil and gas industry operating managers, safety professionals, trade associations and others a road map for targeted improvement programs and priorities for reducing onshore oil field-related fatalities.
The present paper gives an overview of the environmental impact of cuttings discharges on the bentic sediments, three years after drilling an exploration well (7122/7-1) with formate brine (mixture of potassium and sodium formate) in Production Licence 229 in the southwestern part of the Barents Sea.
Eni conducted a high resolution environmental survey on the physical, chemical and biological conditions of the benthic sediments, in the vicinity of well 7122/7-1 drilled in 2000 in PL229. The cuttings and mud from the well were released to the environment as the drilling operation was conducted before the political decision to restrict the discharge of cuttings and mud from operations using water based mud (WBM) in the Barents Sea¹.
The aim of the study was to verify findings in a life cycle assessment (LCA ) that had been conducted for formate brine, which concluded with:
"The findings of the study indicate that the discharge of moderate amounts of Formate Brines is not likely to lead to potentially significant negative impacts on the marine environment." ²
Samples were collected from 27 stations surrounding well 7122/7-1. Apart from the reference station, all stations were within 500 meters of the well head (reference station about 3 km to the south of the well head). Samples from 22 stations were analysed physically/chemically and 19 stations were analysed biologically, in addition to the reference station. As stations were very close to each other, very high sampling accuracy was of crucial importance.
The findings in this study are in line with the conclusion in the LCA as only minor environmental impact in the vicinity of the drilling location was detected.
This paper was submitted for inclusion in a student paper session at the conference.It was included in the proceedings as STUDENT17.
Owing to their properties, oil-products are environmentally noxious, especially for the ground-water environment. In the case of a break-down with an uncontrolled leakage to the environment, only part of hydrocarbons can be removed; a predominant amount of them infiltrate the soil, polluting ground- and surface waters. This results in organoleptic changes in water quality. Besides such leakages have a negative impact on flora and fauna. They accumulate in tissues of the living organisms and hardly undergo treatment.
The physicochemical properties of modified porous glasses Na2O-B2O3-SiO2 are presented in the paper along with the results of experiments on their application to removing hydrocarbons from the environment. It follows from the obtained reduction of pollutions in laboratory samples, that porous glasses can be used as adsorbents for liquidating hydrocarbon pollutions from ground- and surface waters.
Enhanced oil recovery (EOR) has been identified as a promising way of sequestering carbon dioxide (CO2).When CO2 that would otherwise be vented to the atmosphere is used in the process, the CO2 remaining in the ground represents a reduction in greenhouse gas (GHG) emissions.
The accurate quantification of the amount of CO2 sequestered is important as companies look to market the emission reductions associated with EOR operations.Purchasers of emission reductions need assurance that the reductions they are purchasing are real. Often, however, losses of CO2 and methane (CH4) during the operation of EOR projects are not fully considered in accounting for the emission reductions.While minor fugitive losses of CO2 may be accounted for, much larger losses that may occur as a result of the way equipment is configured or how facilities are operated are often ignored.
This paper presents a methodology for quantifying the net greenhouse GHG emission reductions resulting from enhanced oil recovery operations based on the observation of a range of operating facilities.It demonstrates the need to consider the operational aspects of the production facilities in quantifying the amount of GHG emission reductions.It concludes that losses of CO2 and CH4 in EOR operations may be large enough that unless they are fully considered, the magnitude of any claimed emission reductions may be subject to question.
Since 1998, the International Association of Oil and Gas Producers (OGP) has been collecting and collating information on environmental performance from its member companies. The initiative has two principal purposes; first, it addresses the need for greater transparency of upstream industry activities and second, it can provide a means for contributing companies to compare their environmental performance, thereby leading to improved overall industry performance.
Member companies are asked to provide information on 6 categories: atmospheric emissions, produced water, muds and cuttings from offshore operations, oil spills, chemical spills and energy efficiency. Companies also provide information on production levels associated with the data for normalisation. Data are compiled by region (Africa, Asia/Australasia, Europe, FSU, Middle East, North America and South America).
Thirty OGP member companies representing over 40% of the world's oil production now participate in the reporting cycle. Other member companies have begun the internal processes that will enable their participation in future years.
Data coverage is quite uneven; for example almost all production in Europe is reported whilst in other areas performance is reported for a relatively low fraction of the known production.
The reporting exercises have identified and taken steps to solve a range of problems associated with data recording and processing. Information can now be reported to the system via an electronic interface, thereby minimising data transcription errors; the system also allows (by a series of ‘flags') for early detection of possibly spurious year-on-year variations in company reporting.
As the reporting mechanism has developed, the level of confidence within the participating companies has grown steadily and OGP released a summary of information on 2002 activities in 2003. This year, participating companies have agreed to publish data aggregated at a regional as well as a global level.
An integral component of an Environmental Impact Assessment is the Socio-economic Assessment. The purpose of these assessments is to identify and evaluate potential impacts of proposed projects on the socio-economic environment of fenceline communities that would most likely be directly impacted by the project.
With the enactment of the Certificate of Environmental Clearance (CEC) Rules in Trinidad in 2001, Exploration and Production (E&P) companies must now apply to the Environmental Management Authority for an environmental permit for any activity designated under these rules. As a result, oil and gas operators in Trinidad have collected a significant amount of socioeconomic data as part of Environmental Impact Assessments (EIA?s) and Environmental Baseline Surveys for CEC applications.
The state owned oil company, Petrotrin, set the standard for conducting socio-economic assessments for energy development projects in Trinidad and did so on a voluntary basis before the CEC Rules were enacted using guidelines developed by the Regional Association of Oil and Natural Gas Companies in Latin America and the Caribbean (ARPEL).
In conducting socio-economic assessments, surveys were conducted for households, community leaders, business proprietors and focus groups. Generally 25% of the population are interviewed in the process to determine their views and aspirations on potential impacts of oil and gas E&P projects based on their historical experience. If effectively conducted, socio-economic assessments are a valuable tool for determining community needs and ensuring win- win partnerships between oil and gas companies and the communities in which they operate.
This paper describes the process by which Petrotrin has conducted socio-economic assessments for EIA's and Environmental Baseline Surveys for fenceline communities where E&P development activities are planned. It also seeks to give an historical overview of how E&P operations have impacted fence line communities in southern Trinidad over the 20th century.
The paper describes the development, implementation and application of a program of environmental performance measurement in a global service company working the in exploration & production industry.
A set of environmental performance indicators has been defined in order to provide data on internal compliance, environmental incidents, resource consumption, and waste generation (and management). Information is captured in an on-line database from over 500 sites in approximately 100 countries, on a monthly basis, and is immediately available for analysis and management review. The paper discusses the selection of the indicators that are used, and the intended value of each indicator, or group of indicators.
Having described the basis for the EPI program, examples from the data capture and management review process are presented. These examples are used to illustrate the evolution of the EPI process over the past three years. There is particular emphasis on discussion of the challenges that are presented by a highly devolved and decentralized data capture process.
The third section of the paper concerns the trends and themes that are evident from the database, and their application and value to the management process. There is a discussion of indicators that have been removed from, or added to the program and the reasons for those changes.
The paper concludes with a discussion of the possible areas for future development of the program.
This paper presents results of modeling long-term CO2 storage in a shallow saline aquifer with a commercial black-oil reservoir simulator. Realistic CO2/water phase behavior (pVT properties) covering all pressure, temperature and compositional conditions accounted for during the simulations have been used. The pressure and temperature in the aquifer is above the CO2 supercritical conditions giving rise to the existence of a two-phase fluid system of CO2 as a supercritical fluid ("gas") and CO2 dissolved in the aqueous phase. The objective was to model scenarios of CO2 storage in aquifer with emphasis on the sensitivity of CO2 distribution in the deposit with respect to critical CO2 saturations during the injection period and to residual CO2 saturation for water reentering CO2 filled volumes (hysteresis in fluid saturations). The re-distribution of water occurs after stop of CO2 injection due to gravity segregation of dense CO2 saturated water and CO2-free water. The impact of various reservoir parameters has been studied, including average permeability, vertical to horizontal permeability ratio (kv/kh), relative permeability, and capillary pressure. For the saturation functions the main focus has been on end points and hysteresis effects. It is observed that storage of CO2 as residual gas is most important for low kv/kh ratios.