TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractInducing formation damage in sandstone reservoirs through poor drilling fluids management is a crucial factor that can affect well productivity. An integrated team assigned to manage drilling horizontal producers for field development, developed a mud management plan to monitor drilling fluid properties and maintain mud system specifications to minimize formation damage in the field's sensitive sandstone reservoir. This paper discusses the implementation of the engineered oil-based drillin fluid, particle size monitoring, and drilling and completion methods designed to minimize reservoir formation damage and help maximize well productivity.A particle size distribution (PSD) analyzer was used in the field to monitor the PSD values of the particulates in the drillin fluid (DIF) while drilling the sandstone reservoir. Core samples were selected and analyzed using a scanning electron microscope (SEM) to determine an average pore size value.A diesel-based DIF was specifically designed to minimize formation damage. The DIF was formulated with a 70/30 oil water ratio and was treated with a sized calcium carbonate bridging agent to help minimize spurt/total loss. The engineered bridging agent was added to prevent formation damage that results from the invasion of fines. Overbalance pressures were also minimized to avoid the risk of differential sticking.For better bridging results, the D90, D50 and D10 particle size distributions were instantaneously maintained in the programmed range while drilling the entire sandstone pay section with controlled rates of penetration (ROP). The % of drill solids as a function of total solids was also maintained at low levels with the use of centrifuges and addition of whole treated mud. Upon reaching the total depth (TD), the bottomole assembly (BHA) was changed to a reaming assembly and the entire open-hole section was reamed to TD.After making a wiper trip, the operator tripped back to bottom without pumping to simulate hole conditions that would occur while running screens. Once the open hole was deemed in good condition the well was displaced to a solids-free invert emulsion mud maintained at the same density as the DIF. This fluid was circulated over a 230-mesh screen prior to running the screens to ensure that all fine sand and excess filter cake were removed.To date, 26 wells have been successfully drilled and completed with sand screens using the abovementioned methodology. Testing results of the first three wells indicated minimum skin damage and good and stable production rates.
Inducing formation damage in sandstone reservoirs through poor drilling fluids management can negatively affect well productivity. A detailed mud management plan that addresses fluid design and particle size monitoring can help minimize formation damage and improve well productivity. This was demonstrated successfully on 26 wells where the operator implemented an engineered oil-based drill-in fluid (DIF) and a particle size distribution (PSD) analyzer in the field while drilling the reservoir.The oil-based DIF was formulated with a 70/30 oil/water ratio (OWR) and then treated with a sized calcium carbonate bridging agent to minimize spurt and total fluid loss. The PSD analyzer was used to continuously monitor and maintain optimal PSD values in the DIF. In addition, core samples were examined using a scanning electron microscope (SEM) to determine an average pore size value.The bridging agent treatment was engineered to help minimize formation damage that results from the invasion of fines, or colloidal solids. Overbalance pressures were also minimized to avoid the risk of differential sticking. The reservoir section was drilled with controlled rates of penetration.To achieve better bridging results, D90, D50 and D10 particle size distributions were maintained in the programmed range throughout the entire reservoir section. Upon reaching total depth (TD), the bottomhole assembly (BHA) was changed to a reaming assembly and the entire open-hole section was reamed to TD.After the open hole was deemed in good condition, the well was displaced to a solids-free invert emulsion mud with the same density as the DIF.A total of 26 wells have been successfully drilled and completed with sand screens using this mud management plan. Testing results indicated minimum skin damage and good stable production rates.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractNew water-free, oil-based drill-in and completion fluids were recently utilized to drill a sensitive sandstone reservoir. Lower fluid densities were required to safely stabilize the wellbore compared to water-based fluids previously used in the offset wells. Avoiding excessive overbalance pressures eliminated differential sticking, minimized hole enlargement, and significantly reduced formation damage. Upon reaching the target horizontal depth, clean treated oil was circulated to remove the wallcake and solids-free viscosified oil was used as the completion fluid. Two horizontal wells were successfully drilled and completed with pre-pack and expandable screens. Quick clean up was achieved without stimulation. Sustained production rates of these wells exceeded expectations and improved productivity indexes were achieved.
Several old wells have been successfully sidetracked and short radius horizontal holes were placed at the top of the Arab-D reservoir. The main objectives of this type of recompletion are to reduce water coning and improve the oil recovery at the water flood front. Several attempts were made to sidetrack the first well. The downhole motor failed to build the hole angle at the required buildup rate while penetrating the anhydrite formation between the base of Arab-C and the Arab-D. Hole enlargement across the anhydrite section was found to be the reason for the tool failure. Laboratory studies were carried out on anhydrite core samples taken from the base of the Arab-C section. Examination of the core samples by XRD provided detailed mineralogical composition of the rock. To determine the dissolution and erosion effect of different fluids, core plugs were hot rolled in stainless steel cages placed in steel aging cells filled with the drilling fluid samples. NaCl brine-based fluids dissolved up to 3 wt% of the rock sample and eroded additional 7 wt%. CaCl2 brine system treated with Ca(OH)2 and CaS04·2H2Oshowed no dissolution and very little erosion. Oil-based invert emulsion mud with CaCl2 brine as the internal phase showed absolutely no effect on the rock samples. A non-damaging oil-based mud formulation was developed and successfully used to sidetrack and drill several short radius wells. This paper presents the laboratory data along with the drilling and completion fluids formulations being used. Problems that were encountered during the drilling of the first well are also discussed. Introduction Many fields in Saudi Arabia produce mainly from the Arab-D carbonate reservoir which is overlaid by 100 – 170 ft of anhydrite cap rock. On top of the anhydrite lies the Arab-C which, in some areas of the field, is a water bearing and highly pressurized formation. All the field wells are initially completed open hole with the 7 in. liner set at the top of the reservoir. Two methods are used to shut off water entry and increase oil recovery from the unswept zone. In the first method, a short 4 1/2 in. liner is run and cemented across the open hole as shown in Figure-1 and the well is produced by perforating the liner across the unswept oil zones. The second method involves setting a wireline bridge plug capped with 10 ft of cement in the open hole slightly above the oil-water contact. The disadvantage of these methods is the problem of water coning. As oil production continues the water cone rises around the wellbore and as a result, the water production increases until the well dies before the oil in the unswept zone is recovered. Advances in horizontal drilling offer an alternate well completion method that can reduce water coning and increase oil recovery. The process involves cutting a window in the 7 in. casing of the existing well and drilling 500 – 1000 feet of 5 7/8 in. horizontal drain hole into the top of the reservoir as shown in Figure-2. Angle Buildup Problem Several attempts were made to sidetrack the first well as planned (Figure-3). The 100 ft and 60 ft radius motors failed to build the angle of inclination at their designed rates of 57° and 90° /100 ft respectively. The 5 7/8 in. curved hole section was drilled three times to try to place the lateral hole into the target zone. All curves were drilled in a very hard anhydrite formation, between the base of the Arab-C and the Arab-D, and there was no indication of borehole instability.
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