Tar mats at the oil-water contact (OWC tar mats) in oilfield reservoirs can have enormous, pernicious effects on production due to possibly preventing of any natural water drive and precluding any effectiveness of water injectors into aquifers. In spite of this potentially huge impact, tar mat formation is only now being resolved and integrated within advanced asphaltene science. Herein, we describe a very different type of tar mat which we refer to as a "rapid-destabilization tar mat??; it is the asphaltenes that undergo rapid destabilization. To our knowledge, this is the first paper to describe such rapid-destabilization tar mats at least in this context. Rapid-destabilization tar mats can be formed at the crest of the reservoir, generally not at the OWC and can introduce their own set of problems in production. Most importantly, rapid-destabilization tar mats can be porous and permeable, unlike the OWC tar mats. The rapid-destabilization tar mat can undergo plastic flow under standard production conditions rather unlike the OWC tar mat. As its name implies, the rapid-destabilization tar mat can form in very young reservoirs in which thermodynamic disequilibrium in the oil column prevails, while the OWC tar mats generally take longer (geologic) time to form and are often associated with thermodynamically equilibrated oil columns. Here, we describe extensive data sets on rapid-destabilization tar mats in two adjacent reservoirs. The surprising properties of these rapid-destabilization tar mats are redundantly confirmed in many different ways. All components of the processes forming rapid-destabilization tar mats are shown to be consistent with powerful new developments in asphaltene science, specifically with the development of the first equation of state for asphaltene gradients, the Flory-Huggins-Zuo Equation, which has been enabled by the resolution of asphaltene nanostructures in crude oil codified in the Yen-Mullins Model. Rapid-destabilization tar mats represent one extreme while the OWC tar mats represent the polar opposite extreme. In the future, occurrences of tar in reservoirs can be better understood within the context of these two end members tar mats. In addition, two reservoirs in the same minibasin show the same behavior. This important observation allows fluid analysis in wells in one reservoir to indicate likely issues in other reservoirs in the same basin.
Whole level of the erosion and the resistance of rocks which were composed closured have been studied, besides, the impact of temperature and laser irradiation for more investigation about this issue has been involved before all. This subject more reveals the matter which laser absorption on the laboratory scale using laser to what extent can cause the augment of the relative permeability and secondary porosity of reservoir rock, that of the vertical and horizontal useful connectivity and eventually that of the positive transferability.
This research has been carried out in the form of case study on one of Iranian south west formations in north east of Behbahan city in Iran, either the rate or generation of forming the subtle and large fractures has been studied by considering and preparing this section from rocks of stratified sequence of the laboratory area before and after the laser irradiation operation and various analyzer by the means of Spectrophotometer and advanced electron microscope. It should be noted that during the erosion and ablation in the laser drilling operation in the experimental rocks of considered field, given the capability of the field, the formation and field lithology we observed the creation of fractures at the level of micro and nano simultaneously whose vacant spaces were positive, and reservoir and some others were neutral, this fractures can be created by the rate of crude oil absorption. The main purpose of this study is to advance the operations towards the higher technology in order to the better efficiency in the field of the well completion to be gained improving the rate of oil production by the introduction of this modern method of improving and fracturing reservoir which uses certain specialized parameters and indicators, and, finally, the certain method that might be a better way to use laser irradiation on our chosen formation of Iran.
Heavy crude oils and diluted Bitumen ( DilBit ) continue to be a challenge to dehydrate and desalt for the Oil & Gas Industry. These challenges include reduced crude oil / formation water density difference, higher crude oil viscosity and often smaller water droplets due the production techniques used for heavy crude oil production.
The traditional remedy to the above challenges often leads to high operating temperatures, large dosages of demulsifier chemicals, equipment fouling, production upsets and use of very large treaters. This leads to both higher operating expenditure ( OPEX ) as well as higher capital expenditure ( CAPEX ).
Other challenges include higher crude oil conductivity and increased crude oil emulsion viscosity formed by higher water cuts. Typically crude oil dehydration vessels use heat, retention time and AC type electrostatic dehydration technology. The AC technology produces limited voltage gradients and is not efficient for treating conductive crude oils, leading to the use of very large vessels and power units. For AC technology, the use of lower voltage gradient may be preferred.
The use of combined AC / DC electrostatic technologies provides high bulk water removal efficicency in the weaker AC field combined with higher removal efficiency of small water droplets in the stronger DC field. Further improvements include amplitude modulated electrostatic fields, high frequency AC fields, improved electrode configurations as well as improved fluid distribution inside the electrostatic treaters.
More efficient dehydration and desalting processes provide potential for operating the treaters and desalters at lower operating temperatures and reduced dosage of demulsifier chemicals, in addition to the potential for using smaller treaters.
This paper describes potential lowered OPEX for crude oil dehydration and desalting processes, using advanced electrostatic dehydration technologies, efficient test methods for optimized use of production chemicals and selection of electrostatic technologies, including case studies.
Process safety has long embodied the adage, "If you always do what you've always done, you'll always get what you've always got.?? Despite the development of sophisticated technical and management systems in recent decades, major catastrophic incidents continue to occur. Study of these events show us that the technical failures that led to these events were in fact enabled by organizational failures. Yet process safety systems too often exist in isolation from the wider organization, and indeed from other safety activities themselves. In order to achieve next-level improvement, catastrophic event prevention must move from its position of sole (or disproportionate) focus on the safety technical and management systems to a comprehensive focus that encompasses the broader elements of organizational safety as well. This talk presents the problem facing process safety practitioners today and outlines seven principles that can guide leaders both in aligning the organization to support process safety functioning and in assuring the integrity of process safety systems themselves.
Oilfield produced water accounts for 98% of all waste generated in oil and gas exploration and processing. This process water may contain up to 1000 ppm total oil and grease, which must be treated prior to discharge. A novel inorganic adsorbent was designed to have high affinity towards such organics. Lab scale evaluations of this adsorbent on production effluents obtained from an onshore site consistently yields TOG removal > 96%. This was found to be a significant improvement over the chemically assisted DAF at 74% in similar lab scale evaluations. This novel technology has the potential to provide a substancial reduction in capital and operating costs for water treatment.
In a past decade, various nanoparticle experiments have been initiated for improved/enhanced oil recovery (IOR/EOR) project by worldwide petroleum researchers and it has been recognized as a promising agent for IOR/EOR at laboratory scale. A hydrophilic silica nanoparticle with average primary particle size of 7 nm was chosen for this study. Nanofluid was synthesized using synthetic reservoir brine. In this paper, experimental study has been performed to evaluate oil recovery using nanofluid injection onto several water-wet Berea sandstone core plugs.
Three injection schemes associated with nanofluid were performed: 1) nanofluid flooding as secondary recovery process, 2) brine flooding as tertiary recovery processs (following after nanofluid flooding at residual oil saturation), and 3) nanofluid flooding as tertiary recovery process. Interfacial tension (IFT) has been measured using spinning drop method between synthetic oil and brine/nanofluid. It observed that IFT decreased when nanoparticles were introduced to brine.
Compare with brine flooding as secondary recovery, nanofluid flooding almost reach 8% higher oil recovery (% of original oil in place/OOIP) onto Berea cores. The nanofluid also reduced residual oil saturation in the range of 2-13% of pore volume (PV) at core scale. In injection scheme 2, additional oil recovery from brine flooding only reached less than 1% of OOIP. As tertiary recovery, nanofluid flooding reached additional oil recovery of almost 2% of OOIP. The IFT reduction may become a part of recovery mechanism in our studies. The essential results from our experiments showed that nanofluid flooding have more potential in improving oil recovery as secondary recovery compared to tertiary recovery.
The oil and gas industry must face the challenges to unlock the resources that are becoming increasingly difficult to reach with conventional technology. Most oil fields around the world have achieved the stage where the total production rate is nearing the decline phase. Hence, the current major challenge is how to delay the abandonment by extracting more oil economically. The latest worldwide industries innovation trends in miniaturization and nanotechnology material. A nanoparticle, as a part of nanotechnology, has size typically less than 100 nm. Its size is much smaller than rock pore throat in micron size. A nanoparticle fluid suspension, so called nanofluid, is synthesized from nano-sized particles and dispersed in liquids such as water, oil or ethylene glycol.
Through continuously increasing of publication addressed on the topic, nanofluid has showed its potential as IOR/EOR in the past decade. It has motivated us to perform research study to reveal the recovery mechanism and performance of nanofluid in porous medium. We focus on liphopobic and hydrophilic silica nanoparticles (LHP). Miranda et al. (2012) has mentioned the benefit of using silica nanoparticles. It is inorganic material that easier produced with a good degree of control/modify of physical chemistry properties. It can also be easily surface functionalized from hydrophobic to hydrophilic by silanization with hydroxyl group or sulfonic acid. Ju et al. (2006) has initially observed LHP with size range 10-500 nm could improve oil recovery with around 9% (with LHP concentration 0.02 vol. %) compared with pure water. They explained that the recovery mechanism involves wettability alteration of reservoir rock due to adsorbed LHP. Besides, they also reported the porosity and permeability impairment of sandpacks during nanofluid flooding.
In April 2010 we were reminded that Drilling operations are amongst the most hazardous in the world, having the potential for Major Incidents, with the Deepwater Horizon rig fire and explosion. This incident resulted in 11 lives being lost, almost 5,000,000 million barrels of oil being spilt into the Gulf of Mexico over an 87 day period and significant financial loss for bp. This Major Incident also served to remind us that while traditional "Personal Safety?? programs are important to achieve safe drilling operations, these alone cannot effectively manage Major Incident Hazards. E&P Operations can learn valuable lessons from the Process Industry in this regard.
This paper looks at how "Process Safety Management?? implementation, aimed at reducing the potential for Major Incidents, has commenced at an onshore E&P operation. It also discusses the challenges of integrating the culture of Process Safety into existing company culture for operations involving over 60 land rigs comprising both local and international Drilling Contractors and Service Companies.
Process Safety Management system is used to describe those parts of an organisation's management system intended to prevent major incidents arising out of the production, storage and handling of dangerous substances (UK HSE, 2012). It addresses the potential release of these substances caused by:
• Mechanical Failures
• Process Upsets
• Procedures/Human Error
Kuwait Oil Company (KOC) is a subsidiary of Kuwait Petroleum Corporation (KPC), and is involved in the exploration and production of hydrocarbons on land in the state of Kuwait. Existing production is approximately 2.9 mmbopd, with future production targeted at 3.65mmbopd by 2020.
The Exploration and Production (E&PD) Directorate is involved in identifying reserves, drilling new wells and servicing existing wells. It consists of 8 Groups as shown below, and is headed by a Deputy Managing Director (DMD). As most of the PSM challenges in E&PD Directorate lie with Drilling and Service Company operations, the primary focus of this paper will be in these areas.
Al Hamad, Abdullah (Halliburton) | Abdul-Razaq, Eman (KOC) | Al Bahrani, Hasan (KOC) | Surjaatmadja, Jim Basuki (Halliburton) | Bouland, Ali (Kuwait Oil Company) | Turkey, Naween (KOC) | Brand, Shannon (Halliburton) | Al-Saqabi, Mishari Bader (Kuwait Oil Company) | Al-Zankawi, Omran (Kuwait Oil Company) | Vishwanath, Chimmalgi (KOC) | Gazi, Naz H. (Kuwait Oil Company)
There are many ways to stimulate an unlined openhole horizontal well using acid. The simplest way is to just pump acid into the well (i.e., bullhead) without placement control. However, this can often be ineffective. Although still used, such approaches can create massive enlargements at the entry point or high injectivity area, thus causing ineffective treatments and re-entry issues. Wellbore collapse often follows. The use of coiled tubing (CT) as a "pin-point?? delivery method is therefore preferred. Using CT allows dispersal of the acid either uniformly or intermittently along the lateral, as desired. CT also allows acid washing to be performed, which is another common process that can improve stimulation without much additional expense to the operator. Using a jetting tool with many jets, acid can be sprayed onto the wellbore wall, and the active agitation caused by the acid-wash process increases the chemical reactivity of the acid at the desired locations.
Another beneficial approach of using CT is the hydrajet assisted acid fracturing (HJAAF) method. With focused jetting of acid at much higher pressures, the process initiates microfractures in the wellbore walls. When etched with acid, this approach effectively bypasses near-wellbore (NWB) damage much deeper than common washes, thus providing much better results. Further modification of the process by exerting high annular pressures offers the capability of delivering medium to large fractures.
This paper discusses two HJAAF processes uniquely combined into one process used in two large horizontal wells. Because of the large dimension of the inner diameter (ID) of the wells combined with the small production tubing the tool must pass through, the implementation had to be further improved by using a unique jetting mechanism, which positioned the jet nozzles closer to the target. Actual results of such stimulations are presented.
Development of offshore hydrocarbon (HC) fields is today's oil and gasindustry priority in the Russian Federation. Water areas of the Arctic shelfare considered to be potential offshore HC production regions. When designingpipelines for such fields it is necessary to take into account the impact ofspecific Arctic conditions including hazardous ice impact (ice gouging),possible presence of permafrost on the seabed, lithological andgeomorphological distinctive features of bottom soils. All main parametersensuring safety of offshore pipelines must be determined and validated at theearly design stage.
The paper reviews one of the main conditions that influences reliable operationof underwater pipeline systems, namely, stable position of the underwaterpipeline at design reference marks.
Calculations of offshore pipeline stability on the seabed use the followingmain conditions:
- environmental conditions;
- geotechnical conditions of the seabed;
- bathymetrical conditions (water depth);
- pipeline parameters (diameter, wall thickness).
Criteria of pipeline stability on the seabed include:
Soils with weak strength properties, especially when they are used forbackfilling, may be potentially dangerous due to liquefaction underhydrodynamic forces. It is especially dangerous in the first years of operationwhen the soil is not consolidated enough. Relief in a local zone of dilutedsoil causes longitudinal stresses in pipeline, which may result in offshorepipeline stability loss. Liquefied soil potential depends also on backfillingprocess technology. This operation is performed by special ships - dredgers.Such ship has two pipes, one for soil suction, and the other equipped withwater injection nozzles - for washing out and backfilling. When a trench isbackfilled with controlled soil flow, "front" of backfill material is formedunder pipe working head and a layer of fluidized material appears in the upperpart of this "front". Therefore, if weak soil is used as backfill material, asize of liquefied soil layer will be considerable, as well as its impact on thepipeline. This process may lead either to floating up or submerging of pipelineinto the soil. To stabilize offshore pipelines position the following measurescan be taken: backfilling with soil not subject to liquefaction; pipelinelaying below the layer of liquefied soil to eliminate risks related to soilliquefaction; using different methods of ballasting.
Offshore pipelines are a viable option for the safe transport ofhydrocarbons in the Arctic. For continued safe and cost efficient operation, itis important to ensure integrity as well as minimize field inspection andintervention. This can be achieved through an optimized Inspection andMaintenance (IM) program. Determining the required frequency of IM, in a costefficient manner is critical for ensuring integrity and optimizing inspectionand maintenance costs without compromising safety. For piggable lines, smartpigs are used for In-Line Inspection (ILI). A conservative approach (small IMintervals) can be costly, increases the human / Remotely Operated Vehicle (ROV)exposure and yield little new information. A strategy with too little IM canlead to unexpected failures, as too little information is acquired on thecondition of the pipeline. An optimal IM strategy based on the condition ofpipeline is developed in this paper.
In this paper, major Arctic offshore pipeline integrity challenges areevaluated. Considering these challenges, a Risk Based Integrity Modeling (RBIM)framework has been proposed. Design challenges from the effects of ice gouging,strudel scour, frost heave, permafrost thaw settlement, and upheaval bucklingcan be mitigated through proper trenching and burial, as well as conditionmonitoring during operation. The major integrity challenges during operationmay arise from the progressive structural deterioration processes and changesin the right-of-way seabed conditions. The structural deterioration processeswill include time-dependent processes such as corrosion, cracking, andpermafrost thaw settlement. Non-time dependent (random) processes, such asthird party damage, ice gouging, strudel scour, and upheaval buckling will poseadditional risk during operation, but are not addressed in this paper. Theseeffects can be partially addressed through ILI and periodic seabed surveyinspections.
The risk to an Arctic offshore pipeline will be evaluated with respect tothe deterioration processes. The risk is estimated as a combination of theprobability of failure and its consequences. The probability of failure isestimated using the Bayesian analysis. Modeling the structural degradationprocesses using Bayesian analysis is not a new concept; however, modelingdegradation processes using non-conjugate pairs is a new technique that isdiscussed in this paper. Bayesian analysis is based on the estimation of prior,likelihood, and posterior probabilities. Field ILI data is used in theanalysis. The posterior models possess better predictive capabilities of futurefailures. The consequences are estimated in terms of the cost of failure andthe planned IM program. Cost of failure includes the cost of lost product, costof shutdown, cost of spill cleanup, cost of environmental damage and liability.Cost of IM includes the cost to access the pipeline, gauge defects, and carryout inspection and necessary minimal maintenance. Implementation of theproposed RBIM will improve pipeline integrity, increase safety, reducepotential shutdowns, and reduce operational costs.