Steam generation for the purposes of thermal recovery includes facilities to treat the water (produced water or fresh water), generate the steam, and transport it to the injection wells. A steamflood uses high-quality steam injected into an oil reservoir. The quality of steam is defined as the weight percent of steam in the vapor phase to the total weight of steam. The higher the steam quality, the more heat is carried by this steam. High-quality steam provides heat to reduce oil viscosity, which mobilizes and sweeps the crude to the producing wells.

In this second article of a series covering water management in hydraulic fracturing (HF) in unconventional resources, the properties and characteristics of the flowback fluids are discussed, together with the general categories of technologies that are best suited to treat them. As discussed in the June column, the water quality required to make up the HF fluid is a key criterion for selecting the recycle water treatment technology. In some cases, fresh water is required. If the HF flowback water has high salinity, then some form of desalination must be applied. In other cases where salinity can be tolerated, then removal of suspended material is sufficient for recycle. In addition to the recycle water quality, the properties and characteristics of the flowback fluids are important in the selection of water treating equipment. While this may seem like an obvious statement, it requires some justification. There is a need in the oil and gas industry to find a single, flexible, and multipurpose water treatment technology that is capable of handling most flowback fluid types. This would simplify the selection, purchase, deployment, and operation of equipment in the field. From an operations standpoint, the search for a multipurpose technology is justified. However, such a technology has not yet been identified, although there are technologies that come close to meeting the need.

In many operations worldwide, surface waters are injected into producing formations to enhance oil recovery. The types of surface waters used range from seawater (salt water) to lake water (brackish) to river water (fresh water). Surface water must be treated to remove undesirable components before injection. Treatment of surface water for injection requires a specially designed system made up of various components to remove or control any contaminants in the water. The system is engineered to perform the required treatment in the most cost-effective and environmentally sensitive manner. A typical system is shown in Figure 1. Commonly used methods for removal or control of these contaminants are discussed in this section. Surface waters normally contain suspended solids particles that, if injected into the producing formation, will plug the injection well.

Abstract Low-vacuum scanning electron microscopy (SEM) / energy dispersive x-ray (EDX) analysis can be used to characterize the nature of inorganic scale from produced water (Method 1); routinely used to visually determine the degree, form and composition of scale particulates. Quantitative data on scale coverage can be extracted through image analysis, and morphology can indicate origins of particulates (transported scale, active scale…). Recent trends demand more detailed quantitative analysis, believed to produce more accurate / reproducible results. Such a method is automated SEM-EDX particle analysis (Method 2). This has the advantage of full automation and delivers quantitative data on scale coverage, composition, shape and size. Neither method is perfect, the first relies on experienced SEM users, is a manual method, susceptible to bias, and is often perceived as producing qualitative data, while the second method although producing large quantitative data sets, depends upon the criteria used to classify particles, and can be time consuming. Both methods were used to examine a number of filtered produced water samples. The traditional manual method provides good representative results on scale coverage, details on particulate morphology and composition, and can be undertaken in about thirty minutes per sample; it is also a simple matter to differentiate between particulate and blanket scale deposits. The second method generates superior levels of quantitative data, but results are dependent on image thresholding (for particle selection), erroneous misleading results are all too easily obtained (unless rigorously tested particle classification schemes are used), and the method can take in excess of an hour per sample. In general Method 1 should be adequate to track scale issues from produced water, which can be supplemented where desired by automated particle analysis (APA). Where APA is to be used it is recommended that an industry standard classification criterion be developed, which will increase the degree of confidence that can be applied to results, and allow direct comparison of results between laboratories.

Abstract The injection of oil and gas wastes produced during the exploration and production phases have been proven to be an effective technique toward achieving zero discharge. However, several challenges are associated with the injection of slurry into an underground formation. The most common challenge during waste slurry injection (WSI) is the continuous loss of well injectivity due to poor engineering design of the injection parameters for most of the current existing WSI wells. For the WSI operation, near wellbore formation damage (including the fracture damage) will be formed by the injected solids. The real time injection monitoring of the ongoing operations is important to correct any operational mistake and adjust the injection parameters in order to ensure the well longevity. The paper discusses the importance of injection monitoring and steps necessary to maintain the injectivity and perform a healthy WSI operation. Three different case studies are presented to highlight the operational mistakes that caused a significant formation damage development in injectors in Eagle Ford, Haynesville, and Permian Basin shale plays. Certain guidelines depending on the monitoring results are provided in modifying the slurry rheology, pressure, injection strategy etc. that are helpful in maintaining the injectivity. The presented case studies show that the wells with good monitoring program maintained its injectivity during the course of its operation compared to the other wells that lost its injectivity sooner. The results from different case studies are used to prepare a set of guidelines that can be used to maintain the well injectivity and extend the well life. This paper discusses the techniques that will help in eliminating and avoiding the problems leading to formation damage and well plugging during the WSI operation.

Abstract The objective of this paper is to investigate and analyze energy saving and process optimization opportunities in upstream surface facilities, from downhole all the way to the gas-oil separation plants (GOSPs), using value Methodology. Function analysis was used to identify those functions that can be reduced, eliminated, or synergized, to minimize GOSP operating and maintenance cost. In this paper, various energy saving and process optimization opportunities in GOSPs were brainstormed, analyzed, shortlisted, simulated, and validated using actual plant data. Process simulation using Hysys was used to model and verify the feasibility of different process optimization opportunities in GOSPs. A 300 MBD production facility was used to benchmark the Hysys simulation model, and to verify the feasibility of these promising energy saving opportunities. All of the successful opportunities were selected, based on their minimum OPEX and CAPEX, using value engineering methodology.

Abstract Following the last couple of years marked by a drop-in oil price, there has been a requirement to optimize costs for operating and maintaining existing and ageing facilities and equipment and Water disposal wells are no exception. Case study considered onshore wells which were initially completed as oil producing wells in the mid-1970s to early 1980s and in their later life converted for water disposal after the Ultimate Recovery (UR) of the associated reservoirs had been reached and produced water injectivity for wells positively ascertained. The need to initiate this method of produced water management was to ensure its proper and efficient disposal in line with best practices, government regulations and associated cost efficiencies. As these wells stay long in service, they witness several impairments that affect their injectivity. These impairments amongst others include oil slippages, suspended solids, fine sand, corrosion products, microbial activity and carbonate scale particles. These in turn create blockage around perforations which reduce the effective path area for movement of water molecules into subject reservoirs. One of the key actions in maintaining ‘old’ water injection wells is periodic chemical treatment to ensure optimal injectivity. Chemical treatments maybe conducted routinely as a preventive and corrective maintenance activity. As a view to optimising costs we looked to change this to a "Just-in-time" treatment philosophy to manage its overall impact on operating costs and schedule for execution. A surveillance program was developed for older water injection wells which do not have sophisticated sub surface gauges, by relying on surface parameters and associated equipment condition monitoring to schedule chemical treatments for the water injection wells. Some of the surface parameters that was utilized are Water Injection Pump Discharge Pressures, Injection Tubing Head Pressure (ITHP), Injection Flow Line Pressure (IFLP). Following analysis, an empirical system has been developed that enables the prediction for chemical injection treatment without the need to conduct sub-surface investigations using Coil Tubing equipment. This paper discusses a simple, cost effective and easy to use methodology which can be adopted as a first step towards ensuring the adequacy of water injection surveillance program.

Abstract Enhanced Oil Recovery is important stage of life cycle of a field and often it is implemented with challenges. In the chemical EOR, challenges and surprises are expected in production chemistry and production facilities operations. Partially hydrolyzed polyacrylamide used widely for controlling mobility ratio so that Operator is able to recover maximum possible oil. With complex water chemistry and rich in positively charged divalent ions, flooded polymer having negative charge interacts with divalent ions of produced water. Back produced sheared polymer interacts with divalent ions to form semi hard to hard scales poses challenges of the reliability of production facilities. Other important limitations to be noted in CEOR phase are using production chemicals to control scale, emulsion and microbial treatment under Hydrogen Sulphide and waxy crude environment. This paper discusses about the requirement of preparedness and how to overcome challenges of EOR operations and in handling the back produced polymer in following areas: Selection of production chemicals to be compatible to polymer so that no or minimal degradation or loss of viscosity due to polarity of chemicals Performance of production chemicals in the presence of polymer Solids loading in production system Emulsion and produced water treatment Suitability of produced water treatment facilities Revised scaling and fouling control with back produced polymer with rich divalent ions present in produced water Strategizing chemical management system to suit polymer flood and polymerized back produced water treatment regime

Abstract The impact of suspended solids and dynamic conditions on sulphate scale control is well-known. Previous work examined the effect of suspended solids, along with static and turbulent conditions, on one scale inhibitor (Vs-Co). This study has focused on the challenges experienced by an operator of a chalk reservoir field, with a significant amount of carbonate solids in the system, and a high sulphate scale risk due to high barium concentration, injection seawater breakthrough, and cool topside process conditions (20°C). The initial laboratory evaluation showed that the minimum inhibitor concentration (MIC) observed increased from 50ppm to 250ppm after 24 hours (>80% efficiency) under these conditions. A further study investigated whether a reduction in MIC could be achieved with different chemistry. Various chemicals were screened in conventional static jar tests and in stirred tests to induce turbulence incorporating mixed solids. The results showed that many of the conventional scale inhibitor chemistries, working by nucleation inhibition and crystal growth retardation, could not cope with the severe scaling conditions and were less efficient than the incumbent. However, a "novel" scale inhibitor formulation was shown to work more effectively and resulted in a significantly lower MIC than the incumbent. Under sulphate scaling conditions (80:20 FW:SW), VS-Co recorded an MIC of 250ppm which was reduced to ≤100ppm with the novel chemical. This resulted in the opportunity for the operator to reduce their chemical dose rate and logistical costs. This novel chemical works by a combination of nucleation inhibition and crystal growth retardation. As a result of this inhibition mechanism, other operators experiencing similar harsh sulphate scaling conditions could achieve a lower treat rate in high suspended solid loaded systems.

Abstract The South Ratqa heavy oil field, located in the Northern part of Kuwait, will be developed thermally with the first phase of the development expected to become on stream in 2019. The water source to make up steam is coming from the Municipality Sewage Plant Sulaibiya (SWWTP) located in Kuwait City. The Sulaibiya plant is handling sewage water which is locally treated to make it suitable for further use. In the treatment process, RO units are used, and the reject stream of those RO units was identified as water source for the steam plant in the South Ratqa field. In total six steps are required to cover the full treatment scheme of the Boiler Feed Water (BFW) plant, namely: (a) Water Clarifier and sludge treatment, (b) Multimedia and Ultra filtration, (c) Ion Exchange, (d) double Reverse Osmosis, (e) Ozone and Ultra Violet treatment and (f) finally De-aerator. Currently, the plant is being constructed as part of the first phase of the South Ratqa thermal development. Control of bacteria was identified early in the design phase to be crital to ensure successful operation of the BFW plant with minimal down time. Bacteria control will be done at two locations: Upstream of the BFW plant: chemical control of bacteria growth with chlorine addition. Within the BFW plant: mechanical bacteria control using a combination of ozone addition and UV. Upstream of the BFW plant, chlorine will be added in the Sulaibiya plant located 123 km from the South Ratqa field. The project team realized that the added chlorine at this plant would not be enough to fully limit bacterial growth throughout the 123 km pipeline and more importantly, the growth in the 3 storage tanks upstream of the BFW plant. It was then decided to add extra chlorine injection capacity in the BFW plant just before the storage tanks. A suitable test protocol was developed to define the required extra chlorine demand resulting in a residual chlorine level between 0.5 and 2 mg/l entering the BFW plant and taking into account the extra residence times in the process. The extra injection capacity is currently under design. With the help of this extra chlorine addition bacteria growth will be under control and the required high BFW plant availability can be achieved.