This paper discusses a method for optimizing production and operation for onshore/offshore wells. Optimizing the production of oil and gas fields necessitates the use of accurate predication techniques to minimize uncertainties associated with day-to-day operational challenges related to serious operational problems caused by asphaltene deposition. It involves the use of a dynamic flow simulator for modeling oil and gas production systems and reservoir management to determine the feasibility of its economic development. Many studies have focused on relating asphaltene precipitation flocculation and deposition in oil reservoirs and flow assurance in the wellbores. Experimental techniques and theoretical models have been developed trying to understand and predict asphaltene behavior. Nevertheless, some ambiguities still remain with regard to the characterization asphaltene in crude oil and its stability during the primary, secondary, and tertiary recovery stages within the near-wellbore regions.
A synthetic onshore full-field scale that is based on a heterogeneous three-dimensional Cartesian single-well model is considered in this paper. Two wells (a producer and an injector) and one reservoirs are considered to evaluate the dynamic properties under the influence of asphaltene. The size of the reservoir is 25 ft × 25ft × 20 ft and is represented by grid numbers of 50 columns × 50 rows × 5 layers with 12 hydrocarbon components constituting the constant crude composition of this model. The model comprised a total of 12,500 grid blocks. The three-dimensional simulation employed 5-layers, incorporating all relevant production and reservoir data. Different production scenarios were investigated to define the most appropriate and efficient production strategy. This paper provides a method to assess the effect of asphaltene precipitation, flocculation, and deposition in the well productivity and the economic impacts related to it and investigating prevention techniques and other related in-situ pore level flow assurance parameters.
The results will include a comparison of production rates with and without asphaltene precipitation, flocculation, and deposition. In addition, it provides a comparison of asphaltene precipitation, flocculation, and deposition at different times using varying bottomhole and production rate constraints. Several cases (i.e., WAG cycles, completion, target layers of injection, etc.) are tested to help in selection of the optimum completion and operating strategy in the presences asphaltene. The paper will provide insight into factors affecting the flow assurance of oil and gas reservoirs.
Makwashi, Nura (Division of Chemical and Petroleum Engineering, London South Bank University) | Barros, Delcia Soraia David (Division of Chemical and Petroleum Engineering, London South Bank University) | Sarkodie, Kwame (Division of Chemical and Petroleum Engineering, London South Bank University) | Zhao, Donglin (Division of Chemical and Petroleum Engineering, London South Bank University) | Diaz, Pedro A. (Division of Chemical and Petroleum Engineering, London South Bank University)
Production, transportation and storage of highly waxy crude oil is very challenging. This is because they are usually characterised by high content of macro-crystalline waxes, predominantly consisting of n-alkanes (C18 to C36) that which could cause costly deposition within the wellbore and production equipment. The accumulation of deposited wax can decrease oil production rates, cause equipment breakdown, and clog the transport and storage facilities. Currently, different polymeric inhibitors have been utilised in the oil and gas field to mitigate and prevent wax deposition. However, as of today, there is no distinctive wax inhibitor that could work effectively for all oil fields. One of the objectives of this work is to study the efficacy of a blended commercial wax inhibitor - pour point depressant on wax deposition mitigation in a flow rig designed with 0 and 45-degree bends in the pipeline.
Standard laboratory techniques using high-temperature gas chromatography (HTGC), rheometer rig, polarized microscope and elution chromatography were employed to obtain n-paraffin distribution, oil viscosity, WAT, pour point and SARA fractions. Series of experimentation were carried out with and without the inhibitor in a straight pipe test section. The severity of wax deposition in the pipeline built-in with a 45-degree bend is compared with a straight pipe. The blended inhibitor was tested at concentrations of 500, 1000, and 1500-ppm, under laminar and turbulent conditions. The crude oil sample was found to be naturally waxy with wax content of 19.75wt%, n-paraffin distributions ranges from C15-C74, WAT and pour point of 30°C and 25°C respectively. The severity of wax deposition in the test section is 43% higher in 45-degree bend compared to straight pipe. However, the severity of the deposition was reduced to 12.3% at extremely low temperature and flow rate. Nonetheless, better inhibition performance was achieved at 25 and 30°C. The wax thickness was reduced from
For many projects, asphaltene management plans are a matter of remediation or prevention. In the past decade, models have been developed to predict how asphaltene particles will behave in oil—the conditions under which precipitation and agglomeration occur. Rice University has been working on effective models of phase behavior and asphaltene deposition as a path to improved design that can reduce this challenge for operators. As the world's supply of crude becomes heavier, many of the world’s oil producers will have to think more carefully about heavy crudes and the challenges they pose for processing, storage, and transportation.
Operators are looking for ways to better handle water coming from subsea wells, which is typically treated at topside facilities. Subsea separation systems are not equipped to discharge water back into the reservoir, so how do companies close the gaps? High-fidelity 3D engineering simulations are valuable in making decisions, but they can be cost-prohibitive and require significant amounts of time to execute. The integration of deep-learning neural networks with computational fluid dynamics may help accelerate the simulation process. Saudi Aramco studied such algorithms to produce images simulating the flow inside a pipe’s cross section, possibly reducing the need for separator-based multiphase flowmeters.
A new enabling technology known as electrically heat-traced flowline (EHTF) will be used to enable system startup and shutdown and to maintain production fluids outside of the hydrate envelope during steady-state operation. The chemical reactions creating buildups of scale that can clog a well can be replicated in a chemical lab, but researchers are finding many more variables on the surfaces of pipes that need to be considered. Comprehension of the mechanisms that influence wax deposition in oil-production systems has not yet been achieved fully. This paper investigates the influence of the Reynolds number on wax deposition. Erosion caused by fine solid particles presents one of the greatest threats to oil and gas flow assurance, consequently affecting material selection and wall-thickness design.
A multi-phase stimulation treatment was required and subsequently executed in deep-water Gulf of Mexico to remediate a multitude of damage mechanisms resulting from years of hydrocarbon production. Among the many challenges that deep-water operators must face, there is the need for remediation of wells experiencing a decline in production. The execution of these treatments can prove to be very costly and require extensive damage assessments to properly design the most effective stimulation plan. Treatment placement is a major part of the decision process and will impact the performance of the job. A well in the Mississippi Canyon field had an asphaltene deposition issue based on asphaltene onset pressure evaluations as well as suspected fines migration issues. Each requiring its own treatment protocol. This operation required that a rig be moved onto location so that the job could be pumped via coiled tubing to assure injectivity into the zone of interest.
A multiphase approach design included:
The challenge is the difference between utilizing xylene alone for organic deposition removal verses specialty solvent treatments specific to asphaltene removal as well as the use of deep penetrating hydrofluoric acid blends and specialty additive packages.
Utilizing this multi-phase approach resulted in a successful treatment outcome for the operator. An increase in total fluids production, an increase in flowing tubing and a job pay off of less than 30 days was the result of finding a solution to these particular set of challenges.
Wax components can precipitate from petroleum fluids when the original equilibrium conditions of the reservoir are changed so that the solubility of the waxes is reduced; however, wax precipitation does not necessarily lead to deposition. This page discusses wax precipitation behavior and experimental measurements to predict the tendency of a crude oil to precipitate wax. The reason that wax precipitation doesn't necessarily lead to deposition is that individual wax crystals tend to disperse in the fluid instead of depositing on a surface. If the number of wax crystals becomes large enough or if other nucleating materials such as asphaltenes, formation fines, clay, or corrosion products are present, the crystals may agglomerate into larger particles. These larger particles then may separate out of the fluid and form solid deposits.
After precipitation, asphaltene can remain as a suspended solid in the oil or deposit onto the rock. Here, the term precipitation corresponds to the formation of a solid phase from thermodynamic equilibrium and deposition means the settling of solid particles onto the rock surface. Deposition will induce alteration of wettability (from water-wet to oil-wet) of the rock and plugging of the formation. These aspects have been known for a long time and are the subject of many recent investigations. This section reviews the investigations and laboratory observations of these aspects.
Deposition of the high-molecular-weight components of petroleum fluids as solid precipitates in surface facilities, pipelines, downhole tubulars, and within the reservoir are well-recognized production problems. Depending on the reservoir fluid and the type of recovery process, the deposited solid may consist of asphaltenes, waxes, or a mixture of these materials. The deposits also can contain resins, crude oil, fines, scales, and water. Models for solid deposition in the reservoir and in pipelines also are presented. Although some of the laboratory techniques for determining solid precipitation are applicable to both waxes and asphaltenes, the characteristic behaviors of these materials can be very different; therefore, wax and asphaltene topics are treated separately.
Many crudes contain dissolved waxes that can precipitate and deposit under the appropriate environmental conditions. These can build up in production equipment and pipelines, potentially restricting flow (reducing volume produced) and creating other problems. This page discusses how to anticipate, prevent, and remediate wax problems in production. Paraffin wax produced from crude oil consists primarily of long chain, saturated hydrocarbons (linear alkanes/ n-paraffins) with carbon chain lengths of C18 to C75, having individual melting points from 40 to 70 C. This wax material is referred to as "macrocrystalline wax."