Optimized drilling fluids benefit tough Andean wells
Aluminum complex drilling fluids solved common drilling problems in Colombia, Ecuador, Peru, Bolivia, and Venezuela.
Drilling wells in the Andes Mountains of South America face significant difficulties. Wells located in the foothills along the Andean basin are particularly hard to drill because of tectonic stresses and unstable, microfractured shales.
Operators have experienced difficulties drilling wells using both water-based and oil-based muds (OBM). Environmental regulations hinder the use of OBM due to the potential environmental impact and costs associated with waste disposal. In many cases, OBMs have not prevented wellbore instability.
This article explains how wellbore problems can arise from a lack of understanding of regional geology and using drilling fluids and practices designed for other areas. The water-phase salinity of OBM and use of appropriate inhibitors in the drilling fluid play a key role in minimizing wellbore problems.
Although reactive clays are present in all the shales along the basin, they represent only 30-40% of the clay fraction, while nonexpandable kaolinite clays are the major clay components. This article explains how physical and mechanical effects are more important than inhibition in controlling these shales.
Moreover, in some cases, “excessive inhibition” due to the presence of shale inhibitors such as potassium and high water-phase salinity in OBM exacerbate the problems. Pore-pressure transmission caused by fluid invasion is a major contributor. A combination of operational practices and improved fluid design minimizes mud and filtrate invasion.
Troublesome shales in the Andean basin include, from north to south, the La Rosa and Icotetea in Venezuela; the Carbonera, Leon, and Villeta in Colombia; the Napo in Ecuador, the Chonta in Peru; and the Los Monos in Bolivia and Argentina. We present case histories involving these shales.
Contrary to experiences in many other parts of the world, high water-phase salinity OBM and potassium based water-based mud (WBM) are not answers to all shale-stability problems. Rather, mud-sealing properties, correct chemical composition, and appropriate drilling practices are keys in maintaining wellbore stability.
Andean region
The difficulties of drilling in the Andes Mountains of South America are well documented. The presence of tectonic stresses combined with over pressures1 makes this a particularly difficult area.
The stresses in this region were generated by the Andean orogeny. The geology is typified by steeply dipping sand-shale sequences; many faults have been documented. Claystones and shales dominate the lithology in the region. These can be “sticky” at times,2 requiring the use of inhibitive drilling fluids to minimize the associated problems.
Wellbore stability therefore becomes a major problem when drilling in the Andes region, particularly when drilling directional wells.3 Well-documented drilling problems in Colombia include stuck pipe, high torque and drag, tortuous wellbores, twist-offs, poor cementing, and unplanned backoffs.
Many of the difficulties encountered have been attributed to poor hole cleaning in enlarged holes resulting from wellbore instability. The cavings generated during hole enlargement have also presented hole-cleaning difficulties.
Success in drilling wells in this region has been attributed variously to simplifying well design, understanding the tectonic stresses and their orientations, drilling fluid design,4 and sound drilling practices.
Considerable efforts have been devoted to studying wellbore stability issues in the Andes region.5-7 The primary objective of these studies was to improve drilling efficiency. The major conclusion was that it is impossible to prevent borehole instability; rather, it is necessary to find methods to manage it.
Last et al. observed that hole breakout was aligned parallel to the mountains and that there was a clear time-dependency factor. They determined that the most important factors were hole deviation and azimuth, with drilling-fluid formulation, whether WBM or OBM, being of relatively minor importance.
The major cause of wellbore instability was stress-induced failure of relatively weak, naturally fractured siltstones. It was also possible to document mud infiltration with time being vital in determining the onset of wellbore failure. The authors noted the successful use of asphalt products for this purpose.
Studies have compared and integrated wellbore instability issues in the South American basins.8 Wilson et al. concluded that the failure mechanism involves bedding plane slippage in the complex geology of the region.
Studies of other parts of the Andes address similar difficulties posed by the complex geologic conditions in this region.9 10
Drilling fluid design
The drilling of clay, claystones, and shales has always placed great demands on drilling fluids in terms of wellbore stability and drilling efficiency. The drilling fluids industry strives to understand the mechanisms involved in order to improve drilling fluid design.
Recent research performed by the industry shows that several mechanisms are involved and that their relative importance can be estimated:11-16
- Pore-pressure transmission into the formation near the wellbore appears to be very important in very-low-permeability rocks, as confirmed by experiments and analysis.
- Plasticity models better simulate wellbore behavior.
- Anisotropy of the rock can influence failure.
- Capillary effects can help greatly in oil-based drilling fluids by effectively supporting the borehole wall.
- Osmosis, although well understood, is only part of the physico-chemical interactions between borehole and drilling fluid.
- Physicochemical interaction between shale and water-based drilling fluids leads to dissolution of a mineralogical phase of the rock.
- Thermal effects (cooling of the bottom part of the well) can also be significant.
The most important factor in maintaining borehole stability is the prevention of fluid invasion into the shale matrix, thus maintaining hydraulic pressure support of the borehole wall. An ideal drilling fluid, with respect to shale stability, will allow no fluid invasion.
measuring the pressure increase across a shale core as small amounts of fluid enter into the core is an alternative method of measuring borehole stability. Royal Dutch/Shell, BP PLC, and Eni SPA have developed devices for measuring pore pressure transmission (PPT).
The PPT device is designed primarily to measure membrane efficiency and osmotic effects of fluids on shale samples. Several years ago, preliminary PPT testing of aluminum complexes revealed that aluminum compounds could be used effectively to reduce rate of pore pressure transmission in the laboratory device. Fig. 1 shows PPT plots of water-based drilling fluid systems, along with PPT plots for aluminum-hydroxide complex fluids for comparison.
Recently, the device has been a key to the development of aluminum products and high performance water-based mud (HPWBM) systems.17-19
Aluminum chemistry
The Al-chemistry approach to shale stability is based on changing the physico-chemical behavior of the shale, in contrast to the widely applied ionic-exchange approach. Aluminum chemistry has been successfully used in many wells around the world.20-22 The work has been useful in integrating this chemistry into drilling fluid systems.
Aluminum chemistry is also a viable alternative to salt-inhibited systems where environmental regulations discourage the use of chlorides but where shale mineralogy dictates the use of an inhibitive fluid.4
Application of aluminum chemistry in drilling fluids was first described in 1973.23 Early experiences with aluminum chemistry led to enhancements in the chemistry of the products being used. These enhancements, in turn, led to the products being more widely used with better success.
Various theories were postulated as to the mechanism by which aluminum chemistry benefits drilling-fluid performance. It was not until techniques for measuring pore-pressure transmission in shales were developed that the mechanism in the success of aluminum chemistry was identified-the reduction of pore-pressure transmission (as described above).
Yuralpa field, Ecuador
Many problems have been experienced during drilling of development wells in Yuralpa field in Block 21. As seen in Fig. 2, this field has a wide variety of lithologies that have presented many obstacles to the drilling operations.
The Napo shale has produced unstable wellbore conditions in the form of sloughing shale and ledges where limestone interbeds are present. As a consequence, there have been hole-cleaning difficulties, leading to pack-offs of the annulus, and eventually, to stuck pipe.
It is clear that drilling-fluid design was critical to successful drilling of these wells. Based on experience elsewhere in Latin America, including X-ray diffraction (XRD) analysis and shale-fluid compatibility studies, an aluminum complex-amine based fluid was recommended as a replacement for the potassium nitrate-based fluid being used at that time.
Napo shale dispersion tests showed 58.2% dispersion in fresh water, 38.2% dispersion in xanthan gum-PHPA (partially hydrolyzed polyacrylamide) fluid, and 14.2% dispersion in aluminum complex-amine inhibitor fluid.
One operator in 2000 introduced aluminum-based fluids to replace salt-inhibited drilling fluids that had caused severe wellbore-stability problems. Since then, more than 30 wells that include multiple directional and horizontal sections have been drilled successfully. Fig. 3 shows the learning curve for the application of the new system as compared with the conventional inhibited-potassium system.
Optimized drilling fluid design has minimized reaming and back-reaming operations due to enhanced wellbore stability. The continual improvement is clear in Wells A, B, and C.
Well A was drilled at a cost of 26% greater than the budgeted AFE (authority for expenditure). Well B was drilled at 1% less than the AFE, and Well C was drilled at 52% less than the AFE. Table 1 illustrates the recommended parameters for fluid systems used in Yuralpa field.
Cusiana-Recetor field, Colombia
Cusiana field is located on the eastern flank of the Oriental Andes cordillera (Fig. 4). This area is tectonically active, under compression from the eastward movement of the Pacific plate and the southeasterly thrust of the Caribbean plate. Cusiana field lies in an extremely environmentally sensitive area of the foothills.
The basin is within the Llanos basin, and the field is one of the largest in the eastern hemisphere. Development of this field started in the 1990s; more than 130 deep wells have been drilled during the last 15 years, operated by BP.
The drilling problems in Colombia have been well documented.2 3 5-8 24 25 While it is acknowledged that both chemical and mechanical factors affect borehole stability in this region, mechanical factors are believed to be the most critical. The Carbonera shale can produce unstable wellbore conditions in the form of sloughing shale and ledges. As a consequence, hole-cleaning difficulties may be experienced, leading to annular pack-offs and eventually to stuck pipe.
The Leon and Carbonera formations are believed to have been deposited in an estuarine environment. Table 2 shows XRD analyses of the troublesome Carbonera and Leon26 shales. It is clear that these are not “swelling” clays and that any dispersion or instability will be as a result of physical rather than chemical processes.
Various drilling fluids, including both water-based and oil-based, have been used in the field. The oil-based drilling fluids were adapted to the conditions of the basin. The most important change was the use of relatively low water-phase salinities in order to minimize the osmotic stresses. Aluminum complex chemistry was introduced in the Cusiana Buenos Aires field in the late 1990s.
Knowledge of the causes of wellbore instability led to design of a fluid to minimize pressure transmission into fractures and micro-fractures in the shales.
Two methods achieved this:
- Aluminum chemistry, in which an aluminum hydroxide precipitate will form in the fractures when drilling fluid filtrate or whole fluid encounters formation water.
- Asphaltic product, which physically plugs fractures and micro-fractures at the wellbore wall, reducing fluid invasion.
Fig. 5 demonstrates the improvement in drilling performance on the Cusiana wells. The continual improvement is clear with earlier wells being drilled at 90 to 100 ft/day (fpd), and latter wells at 250 to 300 fpd after the introduction of the aluminum complex.
PA field, Peru
PA field is in the foothills of the eastern Peruvian jungle, in the Amazon basin. It is one of several gas fields discovered in the eastern Andes. More than 20 wells have been drilled since development of this field started in the 1990s.
PA field lies in a very environmentally sensitive area of the Amazonian basin. Wellbore-stability problems make drilling the Chambira and Chonta shales difficult. The Chambira shale is very reactive and is located in the lower red beds section. The Chonta shale is micro-fractured and overlies the productive formation. The geologic column in Fig. 2 shows that this field has a wide variety of contrasting lithologies.
Aluminum complex chemistry was introduced in the PA field in the late 1990s during drilling of the PA-1103 and PA-1106 wells. The fluid design incorporated aluminum chemistry for reduction of pore-pressure-transmission effects in the troublesome Chonta shale combined with 3% potassium chloride for inhibition of the reactive Chambira shale formation.
Field results, however, showed the system performed better without the potassium chloride additions. This observation is in line with the adverse effect of potassium on kaolinite-rich shales such as those encountered in these wells. It is clear that drilling fluid design was critical to the successful drilling of these wells.
Well PA-1106 was drilled with a KCl/PHPA drilling fluid in the 12¼-in. interval containing the troublesome Chambira formation. A small concentration of aluminum complex was added at 5,700 ft to improve the hole conditions. Potassium chloride was eliminated from the formulation as a result of the problems experienced in the previous interval. The fluid performance confirmed the adverse effects of potassium chloride in the Chambira formation.
A recently completed exploratory well in this area used a HPWBM. This fluid, which possesses excellent performance characteristics, uses a second-generation aluminum complex. Lessons learned from experiences were as the basis for an optimized aluminum chemistry drilling fluid system for this area.
Palmar, Rioseco fields, Bolivia
The Palmar and Rioseco fields are in the foothills region of eastern Bolivia, in the Amazon basin. More than 20 wells have been drilled since development of the fields began in the 1990s. Many problems have been experienced while during drilling of the development wells on these fields.
Bit balling and accretion, low ROPs, and wellbore instability are common events when drilling through the Chaco, Yecua, Naranjillos, Cajones, Yantata, Ichoa, Cangapi, San Telmo, and Escarpment formations.
Aluminum complex chemistry was introduced to the Palmar and Rioseco fields in the early 2000s during drilling of the Palmar-17 and Rioseco X-100 wells with two different operators, Plupetrol and Don Wong. Aluminum chemistry was introduced as part of the drilling fluid design to control the reactivity of the Chaco, Yecua, Naranjillos, Cajones, and San Telmo formations. Experience elsewhere in Latin America, XRD analysis, and shale-fluid compatibility studies recommended use aluminum chemistry.
The Palmar-17 well was drilled to 11,550 ft with the PHPA-aluminum complex drilling fluid system. In the 8½-in. hole section, the aluminum complex concentration was increased to 5.5 lb/bbl from 2.7 lb/bbl to improve wellbore stability. The well remained stable when two fishing trips were made to recover bit cones. The well was logged with no problems.
The Rioseco X-1001 well was drilled to 7,000 ft with a 12¼-in. bit. This was the first time that this formation was cored with 100% recovery. Use of the aluminum complex system continued during field development. Fig. 6 shows a typical caliper log.
Acknowledgment
The authors thank Perenco’s Carlos Capacho, operations manager, and Oscar Ramirez, project manager, for their support throughout the project.
References
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Based on a poster at the SPE-ATCE, San Antonio, Sept. 26, 2006.
The authors
Mario A. Ramirez ([email protected]) is technical advisor of the TITAN Group at Baker Hughes Drilling Fluids, Houston. He also served as fluids coordinator in several countries and technical manager for the Latin America region. Ramirez holds a BS in chemical engineering from National University and an MS in environmental engineering from Los Andes University, both in Colombia. He is a member of SPE.
Patrick Kenny ([email protected]) is technical services manager at Baker Hughes Drilling Fluids, Houston. He also served as a staff engineer at Statoil, technical services representative at Baroid Drilling Fluids and as a mud logger at NEC GAS. Kenny holds a BSc (1974) from Edinburgh University, Scotland. He is a member of SPE.
Dennis Clapper ([email protected]) is program manager at Baker Hughes Drilling Fluids in Houston. He holds a BA (1974) in chemistry from the University of Missouri-St. Louis and MS (1977) in chemistry from Baylor University. Clapper is a member of the American Chemical Society and SPE.
