Gravel pack operations in poorly consolidated, high-permeability formations are often plagued by relatively low production results, which are caused by the constraints of radial flow, damage to the formation and damage to the gravel pack caused by the treatment fluid. Hydraulic fractures will alter the radial flow for improved production results and will reduce the effects of formation damage caused by the treatment fluid. Data have been generated with several fluid systems that show the damage to the permeability of three different rock types. Fluid loss test results show the expected fluid loss performance of the different fluids. Calculations from recent work are used to show that viscous fluid invasion is also a mechanism for fluid loss control. Fracture conductivity data are provided for 20/40 mesh sands to show performance with the fluids tested. Additional conductivity data with 40/70 mesh sands illustrates the fact that small size gravel pack sands may not provide adequate conductivity for fractured well production. Reservoir simulations compare well performance based on the data provided here. INTRODUCTION Hydraulic fracturing is an established technique for stimulating the production in low-permeability reservoirs and for bypassing damage in moderate-permeability reservoirs. Hydraulic fracturing has recently been applied to high-permeability formations to bypass completion damage and actually stimulate production. Formation fines control in poorly consolidated formations may also be a benefit from hydraulic fracturing. The hydraulic fracture will alter the flow into the wellbore from radial to linear flow. The pressure drop for production will be distributed over the created surface area of the fracture and will not be limited to the surface area of the wellbore or gravel pack radius. This distributed pressure drop will reduce flow rates per-unit area, which will reduce flow velocity which should reduce formation fines movement or production. The lower flow rate over a greater surface area may actually result in higher production rates for the well.1–8 Treatment fluids can damage formation permeability to varying degrees.9 The extent of damage is quantified here for several fluid systems and can be used as a basis to rank fluid systems. This information can also be used to compare radial production and fractured well production when fluid damage to the reservoir is considered in the production calculations.

Hydraulic fracturing is a well established technique for stimulating low permeability formations and for bypassing damage in moderate permeability formations. It is now being applied to high permeability formations (k > 10 mdl to increase production and control formation fines. Fluid selections for these treatments range from typical gravel pack fluids to typical hydraulic fracturing fluids. To determine guidelines for fluid selection, detailed measurements, of fluid loss, core damage, and fracture conductivity were performed under realistic fracturing conditions on cores with liquid permeabilities ranging from 10 md to 1000 md. The bulk of the data presented is on Berea Sandstone ranging from 200 md to 400 md. Results of these tests indicate the relative effectiveness of these treatment fluids for fracturing high permeability formations based on fluid loss, formation permeability damage, and fracture conductivity.Treatment and production simulations are provided stressing the difference in performance between systems.

Completing deepwater Gulf of Mexico (GOM) wells with depths greater than 20,000 ft and high geopressure may require the use of higher-density fracturing fluids to reduce high wellhead treating pressures. In Shell's Deimos field, frac fluid density of up to 12.5 ppg was required. Although the industry has pumped 11.5 ppg NaBr-based borate cross-linked fracturing fluids, a 12.5 ppg NaBr-based borate cross-linked fracturing fluid has not been used until now. There are many challenges when applying a 12.5 ppg NaBr-based borate cross-linked fracturing fluid. The 12.5 ppg NaBr high-density, brine-based fluid has significantly different rheological behaviors than typical fracturing fluids made with freshwater or low salt concentrations. The high-density, borate cross-linked fluid responds very differently to shear history and recovers much more slowly than does freshwater-based fluid. Breaker efficiency is also very different. The highdensity, brine-based fracturing fluid is potentially incompatible with formation crude. Base brine quality was also critical to final fluid quality and quality control procedures had to be better defined. Shell developed lab and field QA/QC protocols to ensure the fluid met the frac & pack job requirements. With rigorous fluid testing and optimizations, three wells in the Deimos field were successfully completed in 2007. This paper summarizes the extensive rheology, fluid compatibility, fluid optimization, and fluid QA/QC processes. It also summarizes important aspects in the application of 12.5 ppg NaBr-based fracturing fluids. This paper will also discuss friction pressure, treatment pressure, actual frac & pack job performance, and postjob production data. The fracturing fluid design and test methodology applied in these three Deimos wells are also very beneficial to design and optimization of other kinds of fracturing applications. Introduction Deimos is a subsalt field located principally in Mississippi Canyon Blocks 806/807/762 in the Gulf of Mexico in 3,000 ft of water, approximately 1 mile west of the Mars TLP. Deimos is located predominantly on the Mars operating unit (Shell 71.5%, BP 28.5%) as shown in Figure 1. The bottomhole static temperature (BHST) ranges from 205°F to 220°F at perforation depths from about 22,000 ft to 26,000 ft MD. The pore pressure is greater than 16,000 psi, and the frac gradient was estimated to be greater than 0.88 psi/ft. The high pore pressure and long MD presented a challenge to pumping traditional frac & pack fluids. For a traditional frac fluid used in the GOM made of 3–7% KCl- or NaCl-based borate cross-linked fluid, the frictional pressure resulting from the long work string and the high pore pressure could result in high surface treating pressure exceeding the 15,000 psi pressure ratings of surface treating equipment and some wellhead components. In addition, high surface treating pressure may also cause the collapse of the bottomhole assembly (BHA).

In deepwater completions in the GOM, synthetic-based mud (SBM) has been widely used for drilling the reservoir section. With increasing well depth and higher reservoir pressure, higher-density drilling fluids are used more and more often. It has been observed that with increasing density of drilling fluid, the incompatibility between drilling fluid, completion fluid, and other well-treatment fluids can cause more problems to drilling and completions. Consequently, the incompatibility can reduce the effectiveness of well completions and result in lower production. Often, the formation damage caused by the incompatibility can be very difficult to remediate. We have identified incompatibility between drilling fluid, completion fluid, and other-well treatment fluids for many GOM wells in lab studies. Chemical additives were studied for preventing the incompatibility between drilling fluid, completion fluid, and other well-treatment fluids. Chemical additives selected from lab study have been applied to many GOM wells, and their use has resulted in improved well production and has prevented catastrophic damage to the wells. We developed proper lab test protocol to subjectively evaluate chemical additives that can prevent or minimize incompatibility between drilling fluid, completion fluid, and other well-treatment fluids. The application of the selected chemical additives on several GOM wells will be discussed. This paper will summarize the lab test methods and lab test results based on testing for several GOM wells. It will also summarize the end results of well performance with the application of these chemicals.

The Parque das Conchas project is located in the BC-10 deepwater block in the Campos Basin, approximately 120 km southeast from the city of Vitoria, in water depths of 1,500 to 2,000 meters. Shell is the operator with a 50% equity share, with joint venture partners Petrobras (35%) and ONGC (15%) 17 . The wells flow via Caisson ESP's to a host FPSO. Horizontal Open-hole Gravel Pack was the sand control method selected in the low frac margin reservoirs of the Ostra Field. In preparation for completing wells in formations with anticipated sand production, a large laboratory study was conducted evaluating the performance of stand-alone woven mesh screens and gravel packs. The study was performed to select a premium mesh screen which would minimize solids production in the event of incomplete gravel pack and manage fines production that would pass through the seabed located Caisson ESP systems. Additionally, it was important to control solids production to the Floating Production, Storage and Offloading (FPSO) unit as there were no provisions installed to handle large volumes of solids at the surface. The test grid compared the performance of multiple screen sizes with and without gravel packs with three unconsolidated formation particle size distributions which were representative of the size distributions anticipated in the completions. The resulting performance data correlated the amount of solids production, size of produced solids, retained gravel pack permeability and retained screen permeability as functions of the effective size of the formation material, the gravel size and the pore size of the screen. The gravel pack media size and premium screen mesh size were selected based on the results of this testing. Screen QA/QC was determined to be critical in the event a full gravel pack was not achieved and the screens would be expected to provide sand control in a stand-alone mode. An enhanced quality process was developed and implemented to ensure the highest quality of the screens was maintained and materials were traceable during well sand control completions.The laboratory tests identified combinations of screen and gravel packs which appeared to indicate the best choice for controlling solids production in an acceptable range while maintaining high flow capacity, maximizing production at minimum drawdown pressures. An enhanced QA/QC process for screen manufacturing contributed to the success of the completions. Production history for the first 2 years indicates minimal sand production.