There is increasing emphasis on enhancing production and extending economic life of mature fields, especially including waterflood operations, globally. With that, it stands to reason that greater focus should be placed on controlling production of unwanted water relative to oil and gas production, as well as on improving the utilization of the large volumes of water to optimize waterflood sweep efficiency. Mechanical and chemical treatment methods for shutting off or at least controlling, unwanted water production have existed for many years. Technologies and methods continue to evolve, albeit slowly. The same is true for injection well treatments for profile modification and improved oil reservoir sweep efficiency purposes. In the family of chemical treatments confined to production wells for controlling water rate are the so-called relative permeability modifiers (RPMs). Despite the long-standing (and continuing) skepticism of RPMs, in general, their implementation has increased in recent years - including uses in conjunction with oil and gas well stimulation treatments. Certainly, some of the criticism of RPMs is justified as they are often misapplied beyond their realistic physical and chemical capabilities. However, the creative application of RPM chemistry in production enhancement applications and in waterflood operations should not be generally dismissed or discouraged. This paper discusses creative uses of RPM systems with properties conducive to application in both matrix and naturally-fractured sandstones and carbonates. Such applications include using RPM systems in hydraulic fracturing, acidizing, scale removal and inhibition, salt block inhibition, and waterflood injection profile modification. Both conceptual and field-proven applications are included. Results of laboratory studies and field case examples are presented. Background Many of the well problems in mature fields can be attributed to the consequences of unwanted water production: Fines migration, sand production, corrosion, scale deposition, water blocks, emulsion blocks, liquid loading, water treatment and disposal challenges. These issues plague mature operations - narrowing operating profit margins and shortening well and field economic life. Given current levels of water production worldwide (estimated at over 4 barrels of water for every barrel of oil), operators and service providers should give greater consideration to the variety of fit-for-purpose water control options they now have. One such area is the application of relative permeability modifiers (RPMs), used generically here for chemical treatments that selectively reduce water flow relative to hydrocarbon flow. RPMs have creative application potential beyond their original and understood use in reducing water production from oil (and gas) wells completed in matrix sandstone formations only. The following sections briefly discuss successful "alternative" applications of RPMs chosen for application-specific properties.

Raageshwari gas field is a relatively deep (3000m) non-conventional volcanic reservoir with a gas column in excess of 800 meters. Gas from Raageshwari field is used to generate energy for production of waxy high pour point crude of the nearby Mangala, Bhagyam and Aishwariya Fields (which were discovered in January 2004) in Barmer Basin, Western Rajasthan India (Figure 1, 2). Extensive laboratory studies have been conducted prior the hydraulic fracturing treatments to evaluate rock mechanical properties, rock -frac fluid interaction and mineralogy. MiniFrac analysis was performed prior to the main frac treatment in order to have a better understanding of the reservoir properties prior to pumping of the main hydraulic fracturing treatment. Microseismic fracture mapping was used to determine fracture geometry and azimuth. Fracture modeling was also used to determine effective fracture geometry which was later calibrated to the Microseismic data. Different techniques have been successfully utilized to overcome extreme fracture complexity and resultant screen-outs including proppant slugs, 100 mesh and high viscosity slugs.

The goal of sandstone matrix acidizing is to remove siliceous particles such as formation clay, feldspar, and quartz fines that are blocking or bridging pore throats. This is accomplished by injecting acid formulations containing hydrofluoric (HF) acid or its precursors, as HF is the only common acid that dissolves siliceous particles sufficiently. Standard treatments include pre-flush and/or post-flush stages of HCl acid to minimize the potential for calcium fluoride and other secondary precipitation. However, there is no guarantee that the HF acid stage will follow the path of the preflush stage; therefore, precipitation could still occur. In addition, the fast reaction of HF acid with clay minerals presents another challenge to effectively stimulating deep sandstone formations. This paper presents experimental and field case studies with a sandstone acidizing treatment designed to retard the HF reaction rate and enable single-stage treatment -eliminating the pre-and post-flush HCl acid stages and thereby reducing treatment complexity and the associated treatment rig time.Extensive laboratory testing was performed using a variety of quarried sandstone cores with varying amounts of clay minerals, feldspar, and carbonate to confirm the ability to stimulate a wide range of sandstone formations. Also, formation core material was evaluated to confirm the results. Static solubility tests indicated that around 80% of the treated formation was soluble in the new acid system formulation. Coreflood testing noted an improvement in permeability of as much as 326%. Also, corrosion tests conducted using different metallurgy showed a very low corrosion rate (less than 0.005 lb/ft 2 for N-80 and less than 0.02 lb/ft 2 for Cr-13). Using coiled tubing, the new design was injected into three deep offshore wells, resulting in injectivity increases of 227%, 236%, and 256%.

Despite modern technological advancements in well drilling and completion, our understanding of hydraulic fracture geometry remains virtually the same as it was at least a decade ago. A critical approach to fracture treatment diagnostics involves an accurate evaluation of near-wellbore perforations efficiency and detection of hydraulic fractures away from the wellbore. The main limitation of currently available fracture diagnostic techniques is that they provide no information about the propped and conductive fractures beyond the wellbore. A cross-dipole acoustic tool and deep shear wave imaging (DSWI) processing are able to detect hydraulic fracture-induced changes within the vicinity and beyond the wellbore. In the near-wellbore region, the acoustic wave transit time increases substantially through the frac sand. The increase in transit time is a function of frac sand porosity. In the mid-field region beyond the wellbore (at approximately one hundred feet), changes in acoustic wave's reflection amplitude between pre- and post-frac measurements illustrate the induced (conductive) fractures and are a strong indicator of the presence of the fracture network away from the borehole. In addition, a three-dimensional fracture radius network model generated from DSWI data can provide greater insight, compared to seismic imaging methods for example, about the presence, location, and characteristics of natural and hydraulically induced fractures. The three-dimensional fracture network model created via DSWI can be more readily used in workflows or tools associated with reservoir modeling and fracture modeling. A novel hydraulic fracture diagnostic technology based on acoustic measurements enables efficient evaluation of the completion and quick, cost-effective hydraulic fracture mapping in the mid-field region. The ability to run a single tool before and after the hydraulic fracture treatment makes this tool a unique solution that helps customers make smart decisions to improve well economics.

The flowback period of the unconventional wells is very critical as it can cause determential ecomonical effects if not properly optimized. The success of the well is as dependent of the completion program as it is from the flowback program applied during the initial production period of the well. If ineffective operations are performed on the flowback phase {independently on the completion technology}, the well can underperform and become unsuitable for development. In unconventional wells, it is necessary to develop the safe well operating envelope in safe zone to prevent the early proppant flowback based on the reservoir parameters and the completions in place. The well can start producing in this developed safe well operating envelope by controlling the wellhead pressure and surface valves and optimizing the proper choke size to keep the well with free proppant production. Proppant flowback production modeling captured decline of water production as well as the increase of liquid production when a selected choke sizes is applied. By controlling the flowing bottomhole pressure (FBHP) during defined flowback period, the volume of proppant production decreased with decreasing chokes sizes and increasing long flowback periods. This study showed that the optimized choke sizes to improve the longer production periods depended on the sensitivity of pressure drawdown, liquid rates, wellhead pressure, and fracture geometry parameters. Numerical results showed that the critical parameters affecting the stability of the proppant pack are fracture closure pressure, reservoir pressure, proppant type and size, and type of fracturing fluid. Proppant flowback program developed by using optimized choke size, wellhead pressure (WHP) and FBHP, and amount of producible proppant volume predicted for designed flowback production periods. At the beginning of the flowback period, the wellbore is filled with fracturing fluid and the minimum choke size should be used as small as possible (12/64"). The controlled FBHP management over 45 days of flowback period corresponds to an average drawdown rate of 10 psi/day to 200 psi/day. Finally, the developed workflow applied to design flowback periods and selection of choke sizes to prevent excessive proppant production and proppant crushing in hydraulically fractured unconventional wells. This paper presents the methodology and workflow for selecting the required choke sizes and flowback periods to minimize the risk of production of high volume proppant during the flowback period after fracturing. The case study presented here in will present the benefits of optimizing choke sizes and flowback programs for reducing the damage to fracture conductivity and to increase the cumulative production. The optimized choke sizes, flowback strategies and workflow established with this case study have proven to increase the performance of fractured unconventional wells.