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Treatment evaluation leads to problem identification and to continuously improved treatments. The prime source of information on which to build an evaluation are the acid treatment report and the pressure and rate data during injection and falloff. Proper execution, quality control, and record keeping are prerequisites to the task of accurate evaluation. Evaluation of unsatisfactory treatments is essential to recommending changes in chemicals and/or treating techniques and procedures that will provide the best treatment for acidizing wells in the future. The most important measure of the treatment is the productivity of the well after treatment.
As with most technology, proper candidate selection is key to success. The economics are often determined by the number of and locations of the wells and by the overall geographical development plan. It is important to recognize that downhole processing is not a substitute for prudent profile control of wells through workovers, gel polymer treatments, cement squeezes, and so on. The following discussion applies to both gas/liquid and water/oil processing, followed by sections that discuss screening criteria specific to each. From an equipment standpoint, gas/liquid separation is much easier than oil/water separation. This generally means that it is a more robust application. All separation and pump equipment has an expected lifetime that is typically much shorter than the lifetime of the well. The cost of replacing or repairing the equipment must be considered as well as the initial capital cost.
While formation damage is typically a problem affecting the productivity of well, it can also pose problems for injection. Understanding the causes of this type of formation damage is important so that efforts to prevent it can be undertaken. This page discusses the types of formation damage that affect injection wells. In such projects, the cost of piping and pumping the water is determined primarily by reservoir depth and the source of the water. However, water treatment costs can vary substantially, depending on the water quality required.
In the process of analyzing treatment responses that occur during hydraulic fracturing, several variances in treating pressure exist that are not readily explained by examining the surface pressures and pipe friction in isolation. These variances are also apparent when looking at bottomhole injectivity. This paper demonstrates how engineers can take advantage of their most-detailed completions and geomechanical data by identifying trends arising from past detailed treatment analyses. The Eagle Ford Shale was deposited in the Late Cretaceous Period in a marginal to open marine setting. The Lower Cretaceous part can be divided into two second-order transgressive/regressive cycles that have been labeled lower and upper Eagle Ford. The deposition of these units varies across the formation as a result of topography at the time of deposition.
The design of a waterflood has many phases. First, simple engineering evaluation techniques are used to determine whether the reservoir meets the minimum technical and economic criteria for a successful waterflood. If so, then more-detailed technical calculations are made. These include the full range of engineering and geoscience studies. The geologists must develop as complete an understanding as possible of the internal character of the pay intervals and of the continuity of nonpay intervals.
Initially, polymer flooding had not been considered as a viable enhanced-oil-recover (EOR) technology for Pelican Lake in northern Alberta, Canada, because of the high viscosity of the oil until it was considered in combination with horizontal wells. Polymer flooding generally has been applied in light- or medium-gravity oil, and, even today, standard industry screening criteria limit its use to viscosities up to 150 cp. Pelican Lake is the site of the first successful application of polymer flooding in much-higher-viscosity oil (1,000–2,500 cp). The Pelican Lake field, approximately 250 km north of Edmonton, Alberta, Canada (Figure 1 above), was discovered in 1978 and started producing in 1980. With more than 6 billion bbl of oil originally in place (OOIP) and a primary recovery estimated at less than 7%, it presents a significant target for EOR.
The First Eocene is a multibillion-barrel heavy-oil carbonate reservoir in the Wafra field, located in the Partitioned Zone (PZ) between Saudi Arabia and Kuwait. After more than 60 years of primary production, expected recovery is low and provides a good target for enhanced-oil-recovery (EOR) processes. A phased piloting approach has been used to reduce the uncertainties (subsurface and surface) related to application of thermal EOR processes in this field. Wafra is one of four major fields located in the PZ (Figure 1). Because of the low primary oil recovery and large original oil in place of the Wafra Eocene reservoirs, a significant EOR opportunity exists.
Polymer flooding is a longstanding, popular tool for improving oil recovery, and over the years a number of researchers have worked at improving the quality of commercially available polymers. However, polymer mixing in offshore applications can present a number of challenges. An SPE Annual Technical Conference and Exhibition session discussed a new approach to better understanding the drivers for polymer hydration and the design of optimal field mixing systems. Researchers hope the information gathered in testing this approach could help with enhanced oil recovery (EOR) in offshore. Do Hoon Kim, a polymer flooding consultant at Chevron, presented a paper (SPE 191391) cowritten with several colleagues from the Chevron Energy Technology Company and Chevron Upstream Europe that presented a new parameter--specific mixing energy (SME)--that can be used to scale-up laboratory mixing.
Produced-water reinjection (PWRI) is an important strategy for deriving value from waste water, but its implementation can face challenges related to injectivity and safety issues. The first objective of a PWRI-design study is to supply water-quality specifications, and the second is to supply injection-pressure specifications. The objective of this paper is to detail how water quality and injection pressure are deduced when uncertainties of input data are considered. Before any PWRI design commences, a feasibility study is performed to assess any compatibility issues and evaluate the risk of scaling and souring and the viability of the project. Bacteria growth and corrosion of the installations have to be tackled and mitigated upstream in the early phase of the project.
Water production normally increases as fields mature, and two main ways exist to deal with the produced water. One is to dispose of the produced water into dedicated disposal wells. The other is to reinject the produced water for pressure maintenance or sweep efficiency. In 2010, a produced-water-reinjection (PWRI) project began in a giant field that involved replacing the aquifer water being injected in one of the water-injection clusters with produced water without water treatment. This project was conducted in a giant onshore field in Abu Dhabi.