The strongest influence on the workforce within most organizations is "the message from the top." To further demonstrate the company and its contractor's commitment to improve Welfare, a formal program for Welfare engagement with workforce known as the " High profile Welfare tour " was launched. High-Visibility Welfare Tours are Labor Camp visits by site management team from both contractors and the company to maintain a "see, hear, and feel" approach towards Welfare and to demonstrate their commitment. The Camp visits are innovative because they go beyond the traditional "Welfare Meeting" between clients and contractors by taking management directly to the camps to engage in direct and personal conversations with labors concerning Welfare issues. Instead of reading, or hearing second hand, about Welfare issues, the message is delivered directly from managers to labors. Additionally, complaints or suggestions are raised directly from labors to managers; hence developing a perfect 360° degree communication between the labors and the site management. Main objectives are to: Demonstrate leadership and commitment by Company and Contractors site management to welfare. Encourage informal discussion between site management and Labors. Identify areas for welfare improvement. Assist in resolving outstanding welfare issues. Follow up and feeding the welfare committee with issues and ensure engagement for timely close-out of arising action. Elevate the level of communication with site and Project management for better understanding and adequate implementation of welfare related issues. Discuss and resolve any emerging issues that are welfare related. Improve moral of employees Demonstrate our Cuture of Caring These tours are organized every other week to maintain contact between the labors and their management and to insure a continual improvement of the welfare conditions. Even though we accommodate more than seven thousand workers from different nationalities and different culture and background in four different camps on ZIRKU Island in Abu Dhabi, UAE on the project, we have managed to tackle all the welfare issues on a timely manner and improve significantly their living conditions, as well moral of employees, and didn't receive any major complaint from the labors since we started the program, which resulted into positive mental health.

Produced water is the largest waste stream generated in oil and gas industries. It is a mixture of different organic and inorganic compounds. Global produced water production is estimated at around 280 million barrels per day compared with around 97 million barrels per day of oil. As a result, water to oil ratio is around 3:1 that is to say; water cut is 70%. Due to the increasing volume of waste all over the world in the current decade, the outcome and effect of discharging produced water on the environment has lately become a significant issue of concern. In certain fields like Asab oil field Abu Dhabi UAE, the produced water is re-injected in the field through injection wells. However, it is found that the concentration of salt in injected formation water in Asab field is 150,000-262,000 ppm and this high saline water is injected in the reservoir. Where it may cause severe formation damage: pore plugging, water injectivity and oil productivity problems. Our objective is to develop a cost effective technique to reduce the salinity of this produced water to control formation damage. We used a couple of chemicals/reagents to reduce the salinity of injected water in Asab field, to increase oil recovery and minimize formation damage such physico-chemical and/or pore blockage. This research examines the sources, characteristics, and extent of different chemicals specially fatty acids and different other techniques that can be used to reduce the salinity of water because no single technology can meet suitable effluent characteristics, thus two or more treatment systems might be used in series operation. However, we were successful to reduce the salinity of brine to approximately 64-74%, where it can be re-injected into the reservoir with minimum formation damage and maximum injectivity.

The aim of this paper is to present the Affiliate's environmental monitoring strategy and summarize results of indicators to follow up cumulative impacts on deep water environment, between 1998 and 2015, which proved to be rather low or negligible, and acceptable on the long term. Since February 1998, when the first environmental baseline study (EBS) was performed (in Block 17: Girassol) to describe the initial state of the environment, the Affiliate has been conducting regular offshore monitoring campaigns with the aim of characterizing the water column, and marine sediments around existing installations and developing fields. These surveys are not limited to Block 17, but also extend to other Affiliate offshore blocks in Angola. In March 2015, the Affiliate's most demanding Global Environmental Baseline & Monitoring Survey (GEMS) was completed, which covered six different offshore blocks, with a work scope ranging between EBS and EMoS (environmental monitoring survey), comprising 226 sampling stations for sediment and benthic macrofauna, 26 for seawater, 17 for phytoplankton and 8 for foraminifera. Another specificity of this latest GEMS was the scientific vessel that was shared among Operators through a joint agreement, of course with some legal and operational constraints considering the socio-geographic context of the project. Technically, besides the Affiliate's required guidelines and rules, the parameters to be tested also had to meet recent regulations from the Ministry of Petroleum. Physico-chemical and biological data obtained over the past 17 years have been used as indicators of environment quality, and its regular monitoring allows assessment of the sensitivity of the marine environment to petroleum activities.

Abstract BP projects in Azerbaijan in the past ten years have installed oil and gas export lines, interfield lines, water injection lines and produced water lines, with a total length in excess of 1000 km- all of which required hydrotesting. This paper describes BP's approach to managing and mitigating the environmental impacts of hydrotest water disposal. The first stage was the selection of a hydrotest chemical package. Candidate chemicals were subjected (individually and in mixture at the appropriate dose levels) to toxicity tests developed specifically for the Caspian, and the least toxic package was selected. The most toxic component of the package was a biocide, which was selected in part for its low persistence and high abiotic degradation rate. The next stage was to assess the dewatering options and to commission dispersion modelling for each option. For each scenario, an ecotoxicological risk assessment was carried out using the modelling results in combination with the toxicity data. Risk assessment concluded that discharge to sea was acceptable offshore but not in the coastal zone. Accordingly, large onshore holding ponds were constructed receive hydrotest water which could not be discharged offshore, and to retain it until chemical analysis and toxicity tests showed that it was safe to discharge. The holding ponds were used to receive hydrotest water in 2005 and 2007. In both cases, analysis showed that the biocide had degraded by > 90% in the pipeline, and that after one week in the holding ponds the residual chemical concentrations and toxicity had decreased to negligible levels. The original toxicity tests had shown that phytoplankton were most sensitive to the biocide. During the 2007 de-watering process, samples taken from the holding pond showed that within one week, healthy phytoplankton populations had become naturally established, providing direct confirmation that discharge of the hydrotest water would present no risk of environmental harm.

Abstract Our hands serve many purposes. Hands help us eat, dress, write, earn a living, create art, and do many other functions and daily chores. To do these tasks and activities, our hands require sensation and movement, such as joint motion, tendon gliding, and muscle contraction. When a problem takes place in the hand, care must be given to all the different types of tissues that make function of the hand possible, achievable and attainable. Presentations of high-pressure water jet injuries to the emergency departments are varied. However, these injuries are sometimes described as a ‘benign variant’ of high-pressure injection injuries; external appearances can be deceptive. These injuries can produce an unexpected pattern of severe and grave internal injury with infectious and vitiating complications. High-pressure water jet injuries from high-pressure jet devices are surgical emergencies characterized by small entry wounds with extensive internal damage. Often subtle and inconspicuous on initial clinical presentation, these injuries can lead to potentially extensive tissue damage underneath. Unfortunately, because the injection itself is often painless, and the lesion usually has a benign appearance, physicians not familiar with the pathophysiology may treat these cases with expectant observation. Three major issues are involved in these injuries. Physical injury is caused by soft tissue disruption and vascular and nerve damage. Chemical injury, depending on the chemical constituents of the injected water, can exacerbate compressive vascular injuries with increased edema and inflammation. Biological injury occurs when injected water, contaminated with virulent organisms and other foreign matter, leads to unusual infections. The key to managing this injury is swift diagnosis and decompression, but delays remain common. Review of high-pressure water jet injuries suggest that prompt diagnosis and early decompression offer the best prospects of digit survival.1,2 History Injuries to the hands caused by industrial high-pressure injections have been reported since the 1930s. Rees first described the condition in 1937, noting an injury arising from a diesel engine injector system.3,4 Only in the late 1950s, however, did the widespread use of high-pressure paint sprays and hydraulic systems increase the incidence of these types of injury. In 1941, Mason and Queen5 described three phases that define the natural history of high-pressure injection injuries (early, intermediate, and late) and their description is still in use today. The prognosis for these injuries was traditionally so poor that Kaufman,6 in 1968, advocated amputation of the digit as the primary treatment. Physics and Mechanism of the Injury The pressure required to penetrate the surface of the skin is on the order of 100 psi.7 However, pressures currently used for high-pressure water jetting can exceed 2500 bars (35500 psi).5 The theoretical velocity of the jet can be derived from the formula: Theoretical velocity = 8.3p (where p is pressure expressed in psi). With water pressures up to 2500 bar (35500 psi), velocity on the order of 1550 mph (2500 km/h) can be encountered. The kinetic energy (Ek) dissipated on impact can be derived from the formula Ek = MV, where M is the mass of water ejected and V is the velocity of impact. Even with parts of the body that have a capacity to absorb only small quantities of water---0.035 oz (1 g) as in the case of a finger---the energy expended may be on the order of 1500 ft-lbf (63.21 J). With other parts of the body, with greater capacity, the energy levels will be much higher. The enormous power of some of the ultrahigh-pressure water jets ranges from 10,000 to an amazing 40,000 psi. This power is focused through a perfected machine nozzle and is often controlled by a human operator. Besides its use on the oil platforms, its applications include concrete demolition, tank cleaning, surface preparation, and heat exchanger and tube cleaning. In many areas, water jet systems are replacing the use of sandblasters as a more cost effective and environmentally friendly and sound alternative; water is easier to recover and recycle than the contaminated sand. Water jetting also offers new solutions to cleaning and preparing surfaces in difficult, confined spaces. It is here to stay and the pressures are constantly increasing; therefore, industry safety practices need to keep up with this powerful tool.

Abstract The PNZ (Partitioned Neutral Zone) has four onshore producing fields bordering Kuwait and Saudi Arabia and is being operated by Joint Operations of Kuwait Oil Company and Saudi Arabian Texaco. The four fields are Wafra, South Umm Gudair (SUG), South Fuwaris and Humma. The majority of production in the PNZ comes from the Ratawi Oolite in the Wafra and South Umm Gudair fields. Production from these fields began in the early 1950s and as maturing of these fields with the passage of time the associated water production has significantly increased which has resulted an environmental hazard in handling and disposal of this vast produced water. This challenge has been met in the past utilizing first surface evaporation pits and then augmented with peripheral water injection into the Ratawi producing reservoir. Today JO is meeting this challenge with the innovative method of horizontal Mega disposal wells completed in the karsted Shuaiba formation. These horizontal Mega wells are capable of taking up to +/- 80,000 BWPD on gravity feed. So currently, +/- 750,000 BWPD of produced water in JO is handled by injection of +/- 220,000BWPD into the peripheral of the Ratawi Oolite in the main Wafra field for the Pressure Maintenance Project (PMP) and through disposal of +/- 530,000 BWPD into the karsted Shuaiba formation. This paper highlights the integrated approach of studying the 3D Seismic interpretation, geologic, and engineering data resulted in the identification of Shuaiba karst Structure as the target disposal zone. The construction and completion of Horizontal Mega wells with 9 5/8″ tubing completion in the Shuaiba karst has resulted in achieving the company target of Zero water disposal in surface pits. It is a remarkable achievement and this technique is uniquely introduced for the first time in Kuwait and could have a potential to be used in the other areas in the Middle East Region. Introduction Until January, 1996 for SUG and January, 2000 for main Wafra about +/- 350,000 BWPD produced water in PNZ was disposed in evaporation pits. The surface pits are environmental hazardous and is undesired practice, therefore JO Management decided to stop this practice and move toward down hole water disposal schemes to achieve Zero Disposal of produced water in surface pits. Shuaiba and Zubair are Lower Cretaceous formations (Fig No.1) that have been penetrated by every Ratawi producer in Wafra Field. Drilling through the Shuaiba has been a concern of severe loss circulation and numerous bottom hole assemblies have been lost due to stuck and hence resulted most of these wells in side tracking the hole. After having study of the characteristics of the Shuaiba formation which represents as wide spread with thick sandstone beds of the Zubair below and Wara / Burgan above. It is Dolomitic limestone, medium to coarse crystalline in texture. It is vuggy to cavernous at time and its thickness changes from 102–180 ft and is spread through out PNZ Field in Wafra. These characteristics appealed to use this formation in benefit of disposing of vast quantities of water produced from different formations rather than disposing in surface pits.

Abstract This document describes data needs for performing cuttings and drilling mud discharge modeling and examples of simple formats for presenting model predictions. The objective is to encourage greater acceptance of discharge modeling as an environmental assessment tool by providing a foundation for consistent modeling study development and presentation. Introduction Drill cuttings and drilling fluid discharge models are available to predict seabed loading and water-column concentrations of drilling wastes. These predictions are an important tool for assessing the environmental impacts of drilling discharges and are often part of an Environmental Impact Assessment (EIA) needed to obtain drilling permits. One example of a model that predicts the fate of discharged drilling wastes is the Offshore Operators Committee Mud and Produced Water Discharge Model (the OOC Model). Several models, however, provide the same types of predictions. This document describes the process of developing a discharge model simulation by describing the input data requirements and methods used to post-process model output into formats that are useful for EIAs. The goal is to promote consistent use of discharge modeling as an environmental assessment tool. The OOC Model The OOC Model is a numerical model that predicts the initial fate of drilling mud and cuttings discharged into the marine environment. The model is also capable of predicting the fate of produced water discharges. The OOC Model, using data describing the discharge conditions, predicts effluent concentration distributions in the water column and the initial seabed deposition distributions of solids discharged from a single point. The model has been validated using laboratory (1,2,3) and field experiments (4,5,6) . Government agencies and industry have used the model to estimate the fate of drilling mud and cuttings discharged in the marine environment. A mathematical description of the model can be found in Brandsma et al. (1) and in Brandsma and Smith (7) . The discussion that follows is specifically applicable to use of the OOC Model. The general input requirements of the OOC Model, however, are applicable to all discharge models. Modeling Process A stochastic modeling approach is used to predict the fate of future drilling discharges because it provides probabilistic results based upon historical information. For stochastic modeling, historical current speeds and directions are used to perform a series of simulations of solids movement in the water column. Each simulation randomly selects current time-series data from an available current data set. The predicted seabed accumulations from multiple model runs are combined to give an overall prediction for a discharge event. Drilling Waste Discharge Types and Discharge Points There are three primary types of solids discharged while drilling oil and gas wells offshore. These are (1) the whole drilling mud solids discharged with water-based drilling mud (WBM), (2) the cuttings and associated drilling mud generated while drilling with WBM and (3) the cuttings and associated drilling mud generated while drilling with nonaqueous drilling fluid (NAF). Most regions allow discharge of both cuttings and whole drilling mud when drilling with WBM. When drilling with NAF, only discharge of the drill cuttings occurs because whole NAF is recycled and reused. The solids discharged with whole WBM have slow fall velocities and wide dispersion when discharged into deep water. Therefore, simulation of surface discharges of WBM solids may not be necessary. A typical deepwater offshore well has two primary points where drilling solids are discharged. For many wells, the top portion is drilled using seawater without a riser to the surface. Riserless drilling results in discharge of cuttings and associated drilling fluid very near the seabed. After the riser is installed, drilling solids pass to the rig and discharges occur through the discharge chute usually within a few meters of the sea surface. Simulating the different discharge points with the OOC Model requires separate runs because only a single discharge point is allowed in a run. Model Input Requirements The following information is intended to assist with the collection of input data needed to perform discharge modeling. Drilling Waste Discharge Types and Discharge Points. There are three primary types of solids discharged while drilling oil and gas wells offshore. These are (1) the whole drilling mud solids discharged with water-based drilling mud (WBM), (2) the cuttings and associated drilling mud generated while drilling with WBM and (3) the cuttings and associated drilling mud generated while drilling with nonaqueous drilling fluid (NAF). Most regions allow discharge of both cuttings and whole drilling mud when drilling with WBM. When drilling with NAF, only discharge of the drill cuttings occurs because whole NAF is recycled and reused. The solids discharged with whole WBM have slow fall velocities and wide dispersion when discharged into deep water. Therefore, simulation of surface discharges of WBM solids may not be necessary. A typical deepwater offshore well has two primary points where drilling solids are discharged. For many wells, the top portion is drilled using seawater without a riser to the surface. Riserless drilling results in discharge of cuttings and associated drilling fluid very near the seabed. After the riser is installed, drilling solids pass to the rig and discharges occur through the discharge chute usually within a few meters of the sea surface. Simulating the different discharge points with the OOC Model requires separate runs because only a single discharge point is allowed in a run.

Abstract This paper will relate Saudi Aramco's operational experience with pressurized hydrogen gas in the annuli of wells equipped with cathodic protection. The presence of hydrogen gas in the effluent samples from the annuli of cathodically protected wells was confirmed in the laboratory and appropriate steps were taken to ensure the safety of wells. These steps include training of personnel involved with well servicing, limitations on welding in the vicinity of these wells and any other activity that could generate a flammable mixture. This paper will discuss the practices of Saudi Aramco in handling this material in a safe manner. Hydrogen gas found in the annuli of cathodically protected wells represents a potential safety hazard since hydrogen gas mixed with air forms an explosive mixture. This odorless and colorless gas is generated as a result of electrolysis of water in the annuli of wells equipped with impressed current cathodic protection to protect the casing from external corrosion. Introduction Cathodic protection is widely used in the oil and gas industry to minimize the occurrence of well casing leaks due to external corrosion. Cathodic protection can be defined as reduction or prevention of corrosion of a metal surface by making it cathodic with impressed current. For well casings this is accomplished with direct current (DC) electricity from an external source to oppose the discharge of current from anodic areas of casing immersed in soil or salt water. In cathodic protection, enough current must be supplied to satisfy cathodic reaction. The cathodic reaction leads to the generation of hydrogen at the external surfaces of well casings. The hydrogen generated by this electrochemical process migrates upward through micro-channels in the cement sheath. The cement may also contain stress induced cracks resulting from curing or mechanical deformation facilitating upward movement of hydrogen toward the wellhead through the well casings annuli. Discussion Historically the only method to reliably combat external corrosion has been cathodic protection. External casing corrosion can be significantly minimized or eliminated through good well completion practices and the use of cathodic protection. Impressed current systems use a current supply, usually a rectifier, to drive the current from anode bed to the casing ( Fig. 1 ). If direct current were applied to the casing in such a manner and magnitude to cause the current to flow up the casing, cathodic protection would be achieved.

Abstract Unocal is the largest producer of natural gas in the Gulf of Thailand. Unocal is faced with finding the most cost-effective way to handle produced water from its oil and gas operations to minimize its impact on the environment. Two options were considered for handling the water: water treatment and water re-injection. This paper looks at the re-injection option and its history and future considerations as it pertains to the Erawan Field. The promising results from early injectivity tests and long term availability of depleted wells have led to full-scale implementation of water re-injection at the Erawan Field. Water re-injection performance begain at 80% of total Erawan produced water and has improved to 92% due to improvement in facility design and overall operating efficiency. Action items have been developed for the immediate, medium and long-terms and incorporated into Unocal Thailand's business unit plan. Typical water injection wells are described as well as good injection well candidates. Erawan Field has 5 major water injection facilities located at each processing platform with bridge connected wellhead platforms. In addition, water is re-injected at 7 remote wellhead platforms utilizing separator pressure vs. aid of an injection pump. Presently, Erawan is re-injecting approximately 20,000 BWPD in 30 wells located on the 12 platforms. Water disposal capacity from the depleted gas wells is estimated at 100+ MMBW. This is equivalent to 15 years of water disposal. Topics to be covered in this paper will be lessons learned, anticipated well characteristics, water management history and future considerations for water re-injection at the Erawan Field. Introduction Unocal Thailand, as a major oil and gas exploration and production company, has been proactive in dealing with the environmental impact of oil and gas production operations. Monitoring on heavy metal and dissolved hydrocarbon content in effluent had long been performed. Since 1996, mercury studies have been conducted in the vicinity of gas processing platforms and remote wellhead platforms in order to detect and measure mercury levels in fish and sediment 1 . The findings have been evaluated both internally and by external consulting firms. As a result, Unocal began several pilot tests in various processing locations to determine the feasibility of either water treatment or water re-injection to address the future environmental impact from heavy metals or other contaminants. In 1997, these pilots led to full-scale implementation of water re-injection disposal at both remote wellhead and processing platforms in the Erawan Field while other facilities proceed with chemical treatment process. Water re-injection has long been utilized in waterflood technology as well as a means of waste disposal for both sludge and produced water. Water re-injection is believed to be the best solution for disposal of produced water in an attempt toward zero discharge and to prevent generation of byproducts from the treatment process.

Abstract Current BP Group Environmental Expectations of zero discharge of oilfield waste to the environment by 2005 and reduction in land-fill disposal options are driving the Company towards innovative disposal schemes that offer attractive and significant environmental and operational cost benefits. One of the current BP initiatives is to merge the synergies of both produced water and drilling cuttings into a single commingled re-injection scheme in the same well. Merging the two technologies for waste disposal in the same formation in the same well becomes a very attractive option, if the well can be engineered and completed to meet the specific objectives of disposing of large volumes of produced water and periodic disposal of drill cuttings from in-fill wells. The main advantages of such a disposal scheme are: Better assurance of fracture containment for disposal of oil-contaminated cuttings. Reduced cost of both operations because of fewer wells and reduced chemicals cost than would be required for separate drill cuttings and produced water disposal schemes. Potential recovery of disposal cost with secondary recovery, if suitable targets are available. BP has successfully implemented commingled re-injection of produced water and drill cuttings in the Wytch Farm and Valhall fields. These commingled re-injection schemes were implemented to address urgent operational need to manage drill cuttings disposal when only water injector wells or producers were available. This paper addresses key engineering issues and risks, which are being evaluated as part of an ongoing BP project to develop engineering guidelines for commingled produced water (PWRI) and drill cuttings (DCRI) re-injection. The paper outlines synergies and differences in current DCRI and PWRI processes and the dominant parameters that are likely to control successful commingled re-injection process. Introduction Management of oilfield wastes has become increasingly important from both economic and environmental perspectives. Within general waste management guidelines, the most acceptable form of waste management is to actually reduce the amount of waste being produced and then to recycle and convert the waste into a usable product, if possible. Disposal of waste is seen as the least preferable solution, but it is often the only practical option, if long term containment and reduced risk to the environment can be assured. Most oilfield wastes consist of oil-contaminated drill cuttings and waste mud from the drilling operation, and production waste (such as completion fluids, produced water, produced sand or back-produced proppant from fracture stimulation jobs). Rig washes or cleaning operations as well as oil-contaminated rainwater may constitute an additional waste stream. 1 The relative amount of production waste to drilling waste will depend on the particular stage of field development, with the volume of produced water dominating the total field waste in some mature fields. Land disposal of untreated oily cuttings and discharge of produced water to sea may not be acceptable without costly pre-treatment of both fluid and solid waste to reduce contaminations (oil, heavy metals, naturally occurring radioactive materials), which may adversely affect the environment. Although some local regulations may permit the discharge of produced water and cuttings to the marine environment, such discharges are not a long-term disposal option. Tightening environmental legislation worldwide and BP's environmental policy of "no damage to the Environment" are reducing opportunities for discharge to sea.

Abstract This paper presents a method to forecast emissions to air from the offshore production of oil and gas. The method enables oil companies quickly to establish reliable forecasts of for instance CO 2 and NO X emissions from offshore oil and gas fields that uses fossil fuels for power generation. The method can also be used to forecast emissions on aggregated levels. The background for developing the method is addressed, the algorithms used and the input data required are described and test results are presented. The method links the emissions to forecasts of oil and gas production and transport, gas and water injection, gas lift and drilling of exploitation wells. In addition, the efficiency in power generation and distribution, the type and LHV of fuel, emission factors for CO 2 and NO X and effects of exhaust gas cleaning systems are incorporated in the algorithms. The method is suitable for estimation of annual emissions over the lifetime of the field in connection with field development planning, governmental reporting as well as for simulation of effects on emissions by altering production strategies and plans. Norsk Hydro has used the method for preparation of the company's annual report of lifetime emission forecasts to the Norwegian Authorities. Norsk Hydro's experience from utilization of the method, including system testing and preparation of prognoses will be presented. Introduction The ability to make reliable forecasts of emissions to air (CO 2 , CH 4 , NO X , VOC) from oil and gas production will be important for the oil industry as well as the authorities to meet future challenges of greenhouse gas trading and commitments related to international protocols. Companies producing oil and gas in Norway (on the Norwegian continental shelf) have to pay a CO 2 tax for all gas flared and all gas and liquid fuel used for power generation purposes. More than 85% of this tax from the Norwegian oil and gas activity is related to fuel consumption. The tax is relatively high (0.09 USD/Sm3 fuel / flare gas), making it a significant part of the operating costs, particularly in the tail end production phase. Reliable fuel forecasts are therefore imperative for proper planning of field development and operation. Norwegian Authorities requires in addition annual reports from the oil companies, containing their best emission forecasts for the remaining production life of each field in operation, under development or in the planning stage. In addition the Norwegian Petroleum Directorate (NPD) makes similar forecasts for fields and reserves in a more premature planning phase. These reports form the input to the Government's national forecasts of greenhouse gas emissions and emissions of NO X and VOC. The flexible mechanisms of the Kyoto protocol opens up for trading of carbon quotas. In order for the oil companies to benefit from this opportunity, reliable forecasts of the CO 2 emissions will be mandatory in their planning process. These challenges call for a forecasting method that links the fuel and emissions forecasts to easily determined parameters, such as the production and injection forecasts and well-known technical parameters. The method has to give reliable results at the same time as it has to be simple to use. This paper describes the background for developing such a method, the algorithms used and the input data required. The practical experience from implementation of the method is also addressed together with results from performed tests. History Norsk Hydro together with the consulting company Novatech started to develop the methodology in 1998 to be prepared for the annual emission forecast report to the Norwegian Authorities. The method was developed and implemented successfully.

Abstract Increasing fuel cost and concern regarding emissions have incurred focus on energy conservation on offshore oil and gas installations. On the Norwegian continental shelf there has been an increased commercial value of natural gas and a CO2-tax on fuel consumption the last 10 years. For the time being the alternative value of natural gas is in the range 0 to 0.06 EUR/Sm3 and consumption of fuel is taxed with approx. 0.09 EUR/Sm3 burned. This has brought forward significant changes in operational procedures and technology development on the Norwegian oil and gas installations compared to installations in other oil and gas regions throughout the world. Focus has increased on keeping the power requirement down, avoiding unnecessary fuel consumption and designing more energy efficient systems. The most efficient way of achieving this is by installing cold process flares and steam cycles on existing or new gas turbines to form Combined Cycles (CC). In Norway three steam cycle plants fueled by gas turbine exhaust are under completion on offshore oil and gas installations. The overall electrical efficiency of these plants is around 50%. When steam is extracted for process heat the overall thermal efficiency is higher. Compared to conventional simple cycles the combined cycle reduces consumption of fuel gas and emissions of CO2 and NOX with minimum 25%. When designed as alternative to conventional simple cycle solutions, a combined cycle represents an alternative investment reducing the size and/or the number of gas turbines needed. This gives a good contribution to the overall Life Cycle evaluation in favor of the combined cycle option when compared to the simple cycle option. Introduction The growing environmental concern with respect to emissions of greenhouse gases caused the Norwegian government to define a self imposed goal of stabilizing the national CO2-emissions on 1989 level by year 2000. This goal has not been achieved. However, there is a new internationally agreed goal defined in the Kyoto agreement which allows Norway a 1% emission increase of greenhouse gases compared to 1990 in the period 2008 - 2012. Compared to 1996this is an decrease of about 7%. As an economical incentive to install more energy efficient technology to achieve reduced emissions, a CO2-tax on hydrocarbon fuel was introduced in 1990. For the oil and gas industry, this was a significant cost increase. Due to the large amount of projects in the NorthSea in the period 1990 until today, the absolute and relative contribution ofCO2-emissions from the oil and gas industry has increased. The national annual emissions of CO2 have rised from 35 to 42 mill tonnesi. In the same period the contribution from the offshore oil and gas industry has increased from approx.20% to 22%. 80% of the offshore emissions comes from roughly 250 gas turbines installed to produce electricity or drive compressors and pumps directly. The efficiency of these machines are in the range of 15 to 35%. The remainingCO2-emissions offshore comes mainly from flaring. The increase in emissions has caused a considerable pressure to develop technology to reduce this trend of increased CO2-emissions.

Abstract BP Norge Ltd. was the first North Sea operator that with a minimum of capital investments attempted to eliminate produced water discharges through the reinjection of mixed produced water and seawater. A full scale produced water reinjection (PWRI) trial started the first quarter of 1995. Performance measurements have included the use of models and documentation of the effects with respect to preventing loss of injectivity. corrosion. scaling, as well as reservoir souring, which have been experienced in previously reported PWRI trials. This paper includes results from the first year of reinjection. It will hopefully promote the industry to consider PWRI as a viable alternative which should be closer evaluated and to provide a foundation for optimising water handling facilities in the future. Introduction Increased environmental concern for the effects of produced water discharges encourages oil producers to consider improving performance at a time when profit margins are small. In addition, it is in the nature of many production systems that the costs of produced water handling increase significantly as the oil field matures when at the same time revenues are in decline. Produced water reinjection (PWRI) is perceived as the most likely method for eliminating the environmental impact of produced water at offshore oil production sites. There is a potential for making cost, space and weight savings through optimisation of water treatment facilities and produced water reinjection system during the life of a field. Reinjection of produced water has been carried out on several locations around the world. BP has, for instance, performed reinjection of produced water in Alaska (Prudhoe Bay) and in the UK (Forties and Wytch Farm). In most cases the activities have been concentrated on individual wells and have not included mixing the produced water with seawater prior to injection. The experiences from these trials have been variable. In most cases some loss in injectivity has been seen, in some cases the problems have been more severe, i.e. accelerated reservoir souring and increased scaling have also been noted. The results obtained from these BP sites have stressed the need for a better understanding of all mechanisms that influence the impact of PWRI. A number of studies are underway in various parts of the world, aimed at creating a better predictive capability of the impact of PWRI in specific field cases. BP Norge (BPN) has been active in these studies and is a member of a UK based produced water reinjection joint industry initiative which is supported by six oil companies. It is an integral part of the Norwegian Research Council's MUST (Environmental and Profitable Development of Small Fields) programme to work closely with these initiatives which provides the opportunity of verifying the relevant predictive models. BPN has accepted that PWRI may be the only way to reduce the produced water discharges, although considerable uncertainty about the costs of implementation and the consequences of reinjection still exist. BPN therefore completed a PWRI trial in one single well on the Ula field in 1994 and based on these results, continued with a full scale PWRI trial in 1995. P. 903

Abstract In 1988 a major onshore production facility was producing oil from eight formations in six oil fields located in the western desert of Egypt. Two of these formations include active water drive reservoirs, in addition; three reservoirs at that date were receiving water injection to enhance oil recovery. To handle the increasing volumes of the produced water (which is contaminated with oil, production chemicals and other pollutants), three alternatives were investigated: – Injection into disposal wells. – Dumping in surface disposal pits. – Re-injection to waterflood some oil reservoirs. The investigation revealed that the first two options are technically unfavorable, also they are conventional Waste Management Technologies (WMT) which provide short-term remedial solution. In contrast, Produced Water Re-Injection (PWRI) is an Environmental Control Technology (ECT) which minimize the environmental impact through process improvements. A state-of-the-art re-injection process was utilized using chemical treatment, gas liberation settling, filtration and injection. This process represents a combination of two (ECT) methods Reuse (for water flooding) and Recycling (when brine is redisposed underground). This process reduce the overall volumes of produced water to be disposed, increase the oil reserves, reservoir pressure and oil production and converse the underground water reserve. It has been concluded that (PWRI) is environmentally safe technically feasible and applicable for similar cases in the western desert of Egypt, it is also more cost effective than usage of the underground water and finally, the chemical treatment and monitoring of the injection-water quality are the keys of successful operation. This paper illustrates; the studies made to prove the technical feasibility of this project, the process designed to treat up to 20,000 BWPD and the contingency treatment facility. Also it demonstrates the field and analytical data showing the improved performance of the process and the environmental quality. Introduction: Khalda petroleum company (KPC) is a joint venture between Egyptian General Petroleum Corporation, Repsol Exploration Company, Phoenix Resources Co. of Egypt and Samsung Corporation working in the oil production. The concession of KPC is located south to Matrouh city in the western desert of Egypt. KPC started its early production from these fields in September 1986. The produced fluids at that date was processed in the process facilities where the separated water is commingled and flow to an API separator to separate the oil content in water by settling. The separated oil is reprocessed again while, water is dumped to a disposal pond in the desert. The producing formations within KPC fields include two active water drive reservoirs and two other formations include partial water drive reservoirs. On the other hand, in 1988 KPC established water injection plant to support the reservoir pressure in three reservoirs. The source of this water injection plant is water source wells producing from Kharita formation. As a result of the above facts, water production from KPC fields was increasing as indicated in (Table-1). P. 915

Evans, R.C., Serck Baker Fluid Systems Consultants SPE Member Abstract Produced water re-injection (PWRI) has become an increasingly important topic in the oil industry in the last few years, especially in mature oil producing areas such as the North Sea. It even has its own acronym. The prime causes for this include the increasing volumes of produced water from mature oil fields, the continued drive to reduce CAPEX and OPEX, and the greater concern over environmental protection. In the latter stages of the economic life of an oil field up to 90% of the produced fluid volume may be water. Detailed planning for the treatment and disposal of produced water is required at an early stage in the development of an oil field to avoid it becoming a bottleneck to production. Among the perceived benefits of produced water injection are; a reduction in the overall volumes of water treated offshore; that the water should not need deaeration if a closed system is maintained; that it could may reduce the potential operating problems associated with scaling and reservoir souring; that the injection zones may be able to accept a poorer water quality than is specified for surface disposal. Subsurface produced water disposal has taken place for a number of years onshore where a typical strategy is to pump the produced water, after various levels of treatment, into a high permeability sand or fractured limestone. However produced water re-injection for pressure maintenance will be a more exacting engineering challenge as operational problems will have a direct impact on production and the profitability of the development. The uncertainties and decisions which will have to be addressed for each produced water reinjection project include; the injection water quality specification; contingency for the surface disposal or storage of the produced water should injection have to periodically halted; the selection and integration of the additional water source which may he required during the early stages of production when the volumes of produced water are insufficient for -pressure maintenance; and the design of the produced water treatment and system. P. 707^

Abstract This paper describes the development of legal and environmental aspects concerning water disposal from onshore mining activities in the Netherlands. The study is based on an existing complex situation consisting of a producing oil field and several sweet and sour gas fields. Production water is injected into the main water drive area under the oil reservoir and into a depleted gas reservoir. Developments in Legislation formed the framework for this study. An Environmental Impact Assessment was required as part of the process of permit application. The most difficult aspect was the continuous changes in Legislation in relation to an on-going technical development. The existing mode of operation, which was injection of production water, turned out to cause the least production water, turned out to cause the least environmental impact. Introduction The Nederlandse Aardolie Maatschappij (NAM) b.v. is the Largest oil and gas producer in the Netherlands. In 1990, 1.4*10 3 m3 of oil and 55.6* 10 9 m3 of gas were produced together with more then 15*10 6 m3 of produced together with more then 15*10 6 m3 of production water. Most of this water is produced production water. Most of this water is produced onshore, the majority resulting from operations in the South-East Drenthe area. The installation of a gas desulphurization plant, in conjunction with specific legal developments necessitated the reconsideration of the treatment and disposal of water. For this reason the procedure for environmental impact assessment (EIA) had to be followed. The main part of this procedure involves the preparation of an environmental impact report (EIR). preparation of an environmental impact report (EIR). In the Netherlands, an EIR describes a proposal for an activity and a number of alternatives, and subsequently predicts the environmental effects of each of these cases. The EIA ensures that environmental aspects, in addition to other considerations, are duly weighted during decision-making. Thus, EIA does not take the place of decision-making but is intended as an aid. place of decision-making but is intended as an aid. This EIA was restricted to the local situation; however, the procedure is also intended for use with other, similar NAM applications for injection permits and will, therefore, serve as a base case. The EIA procedure formally started on 15th May 1990 with the official government publication of a "starting note". This note is open for public comments for one month. Based on this starting note and the comments received, the EIA Commission (Cmer) gave advisory guidelines for the EIR on 6th July 1990. On 26th November 1990, the Executive of the Province of Drenthe set out the final guidelines on behalf of the competent authorities. DEVELOPMENT OF LEGAL ASPECTS Injection of produced water is an integral part of the production process of NAM. Injection has the production process of NAM. Injection has the objectives of removing the excess water that is not discharged into surface water and drainage systems and to increase the production potential by displacing oil with water. Regarding legal aspects, until recently there was no need to take into account the environmental aspects associated with water injection. However, this ceased to be the case after the construction of the gas desulphurization plant at Emmen. This installation receives natural gas containing hydrogen sulphide from the "sour gas" fields. When the installation commenced operation in 1988, sour gas production was increased. The quantity of produced water accompanying this gas thus also increased. The sour gas water was to be injected in the usual way, at a site (MS-18) suitable for receiving hydrogen sulphide containing fluids. P. 83