SPE Copyright 2012, Society of Petroleum Engineers

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1 SPE Improved Heavy Oil Recovery by Drilling Horizontal Wells in Rubiales Field, Colombia A. Florez Anaya, Y. Araujo Paz, M. Uzcategui Rivas, W. Parra Moreno, R. Lavado Quiñones, Pacific Rubiales Energy Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Latin American and Caribbean Petroleum Engineering Conference held in Mexico City, Mexico, April This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract The purpose of this paper is to report the methods used and results of the Rubiales Field development, located onshore in Los Llanos Basin in Colombia. Horizontal well technology was used to drill through unconsolidated sandstones with an active and strong aquifer, under primary heavy oil depletion with an oil gravity ranging from 11.3 to 14.4 API. Horizontal wells allow oil production rate increases, water production delays, oil recovery factor increases, and sand production decreases. The Rubiales Field has an OOIP of 4,608 million STB oil, and a wide reserves volume of 385 million STB oil was certified in June 2011 with horizontal well technology. On 31 December 2011, the cumulative oil production of the field was 163 million STB oil (3.7% recovery factor). Currently, the oil production rate is thousand BOPD, of which thousand BOPD (88.5%) come from horizontal wells. The actual operator company has implemented an aggressive campaign, drilling over 296 horizontal wells from 2006 to Since 1981, 202 vertical wells and 7 deviated wells have been drilled. In Areniscas Basales Unit, the average production rate reached a peak of over 2,000 BOPD for each completed horizontal well. This production rate is almost 7 times that of the neighboring vertical wells production. The placement of the producer horizontal wells has been optimized in the Rubiales Field in locations where the net pay is less than 30 feet by implementing the use of the azimuthal resistivity log, which allows for real-time mapping while drilling up to a distance of 20 feet. In December 2011, 27 horizontal wells were drilled using this technology. The global production rate for these wells is currently 17.5 thousand BOPD. Because of the success of these horizontal wells, the operator company also implemented this technology at the Quifa Field, discovered in 2008, which is an extension of the Rubiales Field. The oil production rate at the Quifa Field in December 2011 was 39.4 thousand BOPD. Introduction The Rubiales Field is located onshore in Los Llanos Basin, 465 kms from Bogota City, Colombia (See APPENDIX A). The field was discovered in 1980 and was first developed in An aggressive drilling program has been pursued to develop the majority of the reserves prior to the expiration of the Rubiales and Pirirí contract on 31 May Rubiales Field consists of 56,000 hectares that produce heavy oil ranging from a gravity of 11.3 to 14.4 API and a high viscosity between 310 and 730 centipoises at 147 F. The producing zone originates in the Carbonera Formation-Areniscas Basales Unit, in which the average thickness ranges from 20 to 80 feet from unconsolidated

2 2 SPE sandstone (See APPENDIX B). The production mechanism is an active water bottom drive and in some cases a lateral water drive due to the presence of shale that acts as a vertical seal. In 2006, the drilling of the first three horizontal wells was initiated with the purpose of evaluating the horizontal construction wells, the increasing oil rate, the water reduction rate, the water breakthrough delay and the reduced sand production without gravel packing. Since 2007, due to good horizontal well performance, horizontal wells were drilled throughout the entire field. The field was developed in clusters consisting of one vertical well and three to five horizontal wells. The vertical well is positioned adjacent to the producer and is designed to allow for geo-navigation control of the horizontal wells. The oil production rate in the Rubiales Field in December 2011 was thousand BOPD, of which thousand BOPD (88.5%) came were collected from horizontal wells. From 2006 to 2011, 296 horizontal wells were drilled. The Rubiales Field was the first field in which horizontal technology was used in Colombia. Geology Characteristics The stratigraphic sequence in the Rubiales Field consists of rocks ranging from Paleozoic to Tertiary (Carbonera, Leon Shale, Guava and Necessity), separated by regional unconformities (see Figure 1-a). The deposition system of braided rivers is composed of mainly sands with lateral deposition bodies that are commonly interbedded with fine overbank sediments. The structure of the Rubiales Field consists of a monocline with a dip below 4 in the direction N50 W. The Areniscas Basales Unit is the producing reservoir in the Rubiales Field (see Figure 1-b). This unit consists of quartz-arenites and sub-arc sandstones that are light gray, fine-grained to coarse and friable, with porosities ranging from 25% to 32% and permeabilities between 5 and 13 Darcy. The formation thickness varies from 130 to 200 feet. The bottom contact is discordant with the Paleozoic and gradually moves toward the ceiling with the Carbonera Intermediate Unit. (a) (b) Figure 1-(a) Regional geology and (b) stratigraphic pattern in the Rubiales Field Reservoir and Fluid Characteristics The Rubiales Field occupies an area of 56,000 hectares, with 20 to 80 feet of oil sand thickness (See correlation in APPENDIX C). The Areniscas Basales Unit depth is between 2,400 feet and 3,000 feet TVD. The production mechanism is a strong artesian aquifer with an oil-water contact tilted in the north-west direction. The reservoir pressure (Figure 2) is typically normal, with 1170 psi at 2700 feet TVD. The reservoir oil is heavy type (11.3 to 14.4 API), has a low GOR (5 to 8 pcs/stb) and has a high viscosity ( cp at 147 F). Development History The Rubiales Field was discovered in 1981 and has been developed sporadically due to global market conditions for heavy oil, beside the geographic conditions (roads, bridges, and the distances from the main towns) and lack of facilities, particularly oil pipelines.

3 SPE Until 2005, the field had been developed with vertical wells with an oil production rate of 4,000 B/D, but in 2006, the first pilot drilling of 2 deviated wells and 2 horizontal wells was performed to evaluate the benefits of these wells compared to vertical wells. The horizontal wells had daily production rates ranging between 5 and 7 times higher than those of the vertical and deviated wells. Horizontal wells produced 1.5 to 2 times longer than vertical wells. In 2007, horizontal wells drilling was initiated. Clusters of 3 to 5 horizontal wells and one vertical well were drilled; the vertical well in a cluster, besides produces oil, is very useful for navigating the horizontal wells. Figure 2 The Rubiales Field reservoir pressure history. Reservoir and Production Challenges Several challenges had to be overcome when horizontal well drilling began. The first challenge was to reduce water production. Although the vertical wells were opened at the top, the wells initially had a high water cut at greater than 80%. The mobility of water was relatively high to oil, and in many cases, there was no barrier permeability to delay the vertical water flow. The second problem was increasing the recovery per well because the majority of the vertical wells did not reach greater than 400 MSTB cumulative oil production, and oil production rates did not exceed 300 B/D. Considering that prior to 2006 oil prices were very low, drilling new wells was not feasible in many cases. The third challenge was reducing formation damage as a result of fines migration and organic damage, which led to gravel-pack plugging and decreased productivity in vertical well completions. Therefore, several organic treatments were applied to recover the wells production. Previous studies have addressed the development of fields for the application of horizontal wells to meet the following objectives: Increase the well productivity. Damage formation and treatment well reduction. Increase the oil recovery factor. Minimize the surface facilities cost and field management. Delay the entry of water into wells. Producing reserves rapidly, that is, produce more quickly. Horizontal Well Technology Application The Rubiales Field has favorable characteristics for horizontal well technology, including the following characteristics: Oil with high viscosity and highly unfavorable oil mobility. Oil thickness with proximity to the aquifer. Strong bottom water pressure. In some sectors with lateral drive due to the presence of some thick clay that acts as a vertical seal. Friable oil sand production that generates fines migration and formation damage in gravel packing.

4 4 SPE Teamwork Initial phase development consisted of identifying and reducing the risks of drilling horizontal wells. The work required experts from a variety of disciplines, including development geology, reservoir engineering, drilling engineering, completion engineering, geo-navigation professionals, production engineering and project engineering. Understanding the stratigraphic formation in the area, as well as the potential associated problems, helped to minimize the risks associated with the horizontal well drilling. Development Geology: Many factors were evaluated when selecting areas for horizontal well drilling, including analyzing the geological model; defining the objectives; analyzing the lateral continuity, petrophysical properties, and fluid distribution of the oil regions; and defining the oil-water contact point. Choosing the location of a horizontal well requires stratigraphy knowledge and reservoir sedimentology. Typical challenges in the Rubiales Field were thin sand, the sand continuity and the development at the top of the Areniscas Basales Unit. To minimize risk and uncertainty, vertical wells were drilled first to tie the well according to 2D seismic data. The model was updated using 3D seismic data in 2007, and the new wells were drilled. Drilling Engineering: Drilling engineers contributed to the design of the geo-navigation paths, the casing point definition, the isolation type for the aquifer zones and the contract packages to reduce costs. The stratigraphic column indicates that the Carbonera formation is located below the Leon Shale formation, which has an average thickness of 800 feet. This shale does not present potential problems during the drilling process because it exhibits low sensitivity to water drilling fluid. The Carbonera formation is a sequence of interbedded sands and shales. The sand is subdivided into Sand C1, Sand C2, Sand Middle and Areniscas Basales Unit. These sands are friable and have a strong water drive that results in instability, tight spots and the implemention of gravel pack. Additionally, when the well trajectory must navigate on top of Areniscas Basales Unit, characteristic shale and hydrocarbon traps may be encountered, which makes a landing from 85 to 87 degrees difficult. Reservoir Engineering: To drill the new horizontal wells, the selected area must demonstrate good geological control with previously drilled vertical wells, oil thicknesses greater than 20 feet and good production results in vertical wells (more than 350 MSTB oil). To obtain higher oil production rates and delay the entry of water, the wells were designed to navigate on top of the Areniscas Basales Unit, where the drainage hole was the furthermost from the oil-water contact point and where 1 or 2 vertical barriers were present that delayed the entry of water from the bottom aquifer. The well trajectory was designed with conceptual simulation models to predict well behavior. Water production problems and coning were identified as the key factors used to define the path and horizontal well length. The optimum navigation length was determined through simulation conceptual models, yielding an optimal average navigation value of 1,200 feet. Completion Engineering: The optimal horizontal well completion and the assembly production design were the main points of discussion during the planning process. Slotted liner and open hole completion for horizontal section were evaluated, and the open hole in Areniscas Basales Unit was discarded because of its unconsolidated condition. Slotted liners were selected for their lower costs and effectiveness due to the coarse-grained sand formation with low fines production. The results using the slotted liners have been proven in terms of production and sand control. In several cases, sand production and plugging of the horizontal section have occurred. However, it is unclear whether these problems resulted from the design of the slotted liner, liner defects or problems with the operation. Artificial lift systems were used because of high volumes, with rates above 10 thousands B/D of total fluid. Electric submersible pumps have been used successfully with lifetimes of more than 1,000 days. Design of Horizontal Wells The Rubiales Field development was carried out with vertical wells using two completion types, one with open hole gravel packing and another with cased hole

5 SPE gravel packing that had previously been cemented and shut. In the beginning of 2006, horizontal well drilling commenced according to the new development plan. Vertical wells were also drilled, with 12 ¼ in. hole and 9 5/8 in. casing, J-55, 36 lb/ft, at an average depth 260 feet. The casing was cemented to protect the surface water. At this point, drilling with 8 ½ in. bit and covering with N-80 casing, 23 lb/ft to the top of the Areniscas Basales Unit was achieved. The length from the kick point to the entry point was approximately 450 meters, and the drill depth was approximately 4,500 feet. This section is covered with a 7 in. casing, 23 lb/ft, N- 80, and cemented to isolate the aquifer above the Areniscas Basales Unit. The horizontal section is 1,200 feet, drilled with a 6 1/8 in. bit and cased with a slotted liner 4 ½ in., 11.9 lb/ft, N-80, designed with 224 slots/ft. with a slot opening in. that was 1.5 in. long. In Figure 3-a, the mechanical diagram of the horizontal well in the Rubiales Field is shown. This horizontal well design is considered standard for the area, and it has proven to be the most economical in terms of cost, location, hole size, production rate, casing size and impact on the outcome of directional drilling in time and cost. Horizontal well drilling time is approximately 13 days per well, at which point the well is completed and ready for production. The typical well array involves a centralized vertical well with 3 to 5 horizontal wells drilled outward from the same pad location, as shown in Figure 3- b. (a) (b) Figure 3-(a) Correlation and electrical recordings of horizontal well mechanical conditions. (b) Cluster configuration for horizontal wells. The first step of horizontal well drilling requires drilling the vertical well of the cluster to set the litho-stratigraphic correlation and improve the geological control. The neighboring wells are then drilled. During drilling, conventional tools have been used, including LWD (logging while drilling) and specialized tools for geo-navigation. The first goal is to make the litho-stratigraphic correlation, fluid real-time resistivity curves and gamma rays. The goal of specialized tools for geo-navigation and the adjustment of litho-stratigraphic correlations and fluid are to map conductive surfaces (seals and water areas), which helps maintain better contact with the reservoir and avoid operational problems such as broken seals close to water areas. To ensure that the planned trajectories are accurate, it is essential to support the tools that measure the inclination of the hole at a distance closer to the bit, typically from 4 to 30 feet. Among the main operational problems, the inclination loss due to the ease with which friable sand can be washed should be mentioned. Conventional drilling tools require a much longer slide to restore and maintain horizontality. When specialized geo-navigation tools are used, the problem is more

6 6 SPE complicated because these tools are azimuthal and thus require permanent rotation for data acquisition. Another problem is caused by lithological variations that are generally associated with facie changes, as the directional string responses can vary dramatically, complicating horizontal drilling. Equally complicated are the cases in which very thin layers or layers with high clay content in the matrix mask the electric log response and occasionally lead to incorrect decisions. Resistivity can be affected by layer effects and/or polarization due to the drilling angle. When a horizontal well is planned, it is important to consider whether the assumed ideal geological conditions of continuity in the reservoir under normal conditions are necessary for drilling. Changing the plan according to information obtained from LWD logs and channel samples may be necessary. A well might have high tortuosity even though it always meets the goal of having more contact with the reservoir, either because the entire section is achieved within the layer proposal or because different sands are interconnected. Figure 4 shows a section of the horizontal well trajectory. Figure 4 - Horizontal well trajectory the Rubiales Field. Production Forecasting - Horizontal Wells Well spacing was determined using modified Joshi drainage models, which have drainage radius values of 150 meters at the ends of the horizontal well and 300 meters on the sides of the well and a horizontal length of 1,200 feet. This model covers an area of approximately 90 acres. Four horizontal well types were identified based on well spacing; well type was dependent on oil thickness, the seal thickness under the oil sand and distance sealed into the aquifer. The well types have been updated periodically, typically every year, as progress has been made in drilling horizontal wells. Figure 5 shows the production behavior of the 296 horizontal wells in December 2011 compared to the predictions for the four well types. Figure 5 shows that the type 1 wells (blue line) reach a maximum production rate of 2,500 BOPD, with an oil cumulative volume of 2.0 million STB. The type 2 (green line) wells reach a maximum production rate of 2,000 BOPD, with an oil cumulative volume of 1.5 million STB. The type 3 (black line) wells reach a maximum production rate of 1,400 BOPD, with an oil cumulative volume of 1.2 million STB. The type 4 (line red) wells reach a maximum production rate of 900 BOPD, with an oil cumulative volume of 0.7 million STB.

7 SPE Figure 5 - Horizontal well production history and well type forecasts. Drilling Results From 2006 to 2011, 296 horizontal wells were drilled, and during the entire field history, from 1981 to 2011, 202 vertical wells and 7 deviated wells have been drilled. Horizontal wells represent a section navigated total of thousand feet, with an average length of 1179 feet per well. The net oil length is thousand feet (82%), for an average of 967 feet per well. Figure 6 shows the distribution of thickness in the entire section that was navigated. Figure 6 Horizontal navigated distribution thickness. Production Results The Rubiales Field production rate in December 2011 was thousand BOPD, of which thousand BOPD (88.5%) came from horizontal wells (Figure 7-a). The field oil cumulative production volume is 163 million STB, of which million STB (83.1%) was produced by horizontal wells. Horizontal wells have presented average oil production rates per well ranging from 2,000 to 750 B/D (Figure 7-b). Similarly, horizontal wells produce between 4 and 7 times more oil than vertical wells (Figure 8).

8 8 SPE (a) (b) Figure 7 (a) Daily oil production rate for horizontal and vertical wells and (b) average daily oil production rate for horizontal and vertical wells. Figure 8 Horizontal/vertical oil production ratio. Recovery Factor The recovery factor was calculated by selecting a central area of the field, which is colored red in Figure 9. The selected area covers a total of 3,804 acres and 44 wells, 18 of which are vertical wells (3 well replacements) and 26 of which are horizontal wells. The calculated OOIP ranges from (P90) to million STB oil (P10) with an average value (P50) of million STB oil. The optimal recovery (EUR) predicted for these 44 wells is 48.5 million STB oil. With the value of EUR and OOIP in the sector, the recovery factor varies between 21.9% (P90) and 22.6% (P10) with an average value (P50) of 22.3%. The estimated recovery factor for vertical wells in the same area is 12%, indicating that the horizontal wells recovery is approximately 10% higher.

9 SPE Figure 9 - Selected Area for calculating the recovery factor. Reserves Rubiales Field has an OOIP of 4,608 million STB. The reserve certification report is effective as of June The field-wide proved, probable and possible reserves volume is 385 million STB. Proved reserves have been estimated at million STB, of which thousand STB are from proved developed reserves (RPD). The field development plan is built for a plateau of 180 thousand BOPD when drilling pads with horizontal wells. The production history and the forecast for the proved developed reserves are presented in Figure 10. Figure 10 - Proved developed reserves Rubiales field New Technologies Azimuthal Resistivity Tools: As the Rubiales Field was developed with horizontal wells, new oil-prospective areas were discovered. Some of these areas have low thicknesses between 20 and 30 feet, which made it difficult to navigate horizontal wells to

10 10 SPE optimize the recovery in these areas. Directional drilling technology has involved with high-resolution azimuthal resistivity tools. These tools allow for mapping the limits of the layers at distances of up to 20 feet, through resistivity contrasts in real time while drilling. As of December 2011, 27 wells have been drilled with azimuthal resistivity tools. The production peak of these wells is 17.5 thousand BOPD for an average of 648 BOPD per well. Figure 11 shows an example of navigation from well RB-376H using an azimuthal tool. Navigation is maintained at 3 to 7 feet TVD relative to the upper resistive contrast with the top of the Areniscas Basales Unit. The navigable length of 1,275 feet was measured with resistivities greater than 100 ohm-m. The cut-off for oil-sand minimum resistivity is 50 ohm-m. This well yielded an oil production rate of approximately 2,000 B/D for over 3 months (see Figure 12). Figure 11 Azimuthal log in RB-367H in horizontal section. Figure 12 History of production of RB-367H. Inflow Control Device (ICD): Horizontal wells in the Rubiales Field were made by placing a slotted liner in the open hole. This type of completion has some disadvantages, namely, it does not allow the control of water flow. A limited number of horizontal wells have had to be closed early due to a high influx of water through one of the horizontal section. To improve the sweep in horizontal wells and delay the entry of

11 SPE water, ICDs have been used in conjunction with inflatable packaging to subdivide the horizontal section and better distribute the fluid ingress into the well. Given that there are several types of flow controllers on the market, see Figure 13-a, a pilot study will be performed with three different types of ICD that were designed based on the independence of the viscosity as the main parameter. The Rubiales oil field has viscosities ranging from 310 to 730 cp at 147 F. The performance of the wells will be evaluated during the first 6 months to define the use of the ICD in critical areas of the site where the thickness is less than 20 feet. Figure 13-b presents a schematic diagram of a well without an ICD. It can be observed that the water enters a section of the well (the most permeable zone) and leaves without affecting much of the other section. Figure 13-c shows what happens in a well when an ICD is used. In this case, fluid distribution is homogeneous. Figure 13 - (a) Nozzle type and helical-channel type and (b) production without ICD and (c) production with ICD. Conclusions Reservoir characteristics in Rubiales Field, such as high oil viscosity, a small thickness and drive water, make the reservoir produce with highly adverse mobility. Horizontal wells constructed with a slotted liner were inexpensive, easy to download and effective in terms of production and sand control. Horizontal wells in the Rubiales Field have produced between 2,000 to 750 BOPD. The horizontal wells produce 4 to 7 times more oil than the vertical wells.

12 12 SPE As of December 2011, 296 horizontal wells and 202 vertical wells have been drilled. Horizontal wells represent a navigated section total of thousand feet, which corresponds to an average length of 1,179 feet per well. The net oil length is thousand feet (82%), with an average length of 967 feet per well. The recovery factor achieved in a central sector of the field using horizontal and vertical wells ranges from 21.9% (P90) to 22.6% (P10), with an average of 22.3% (P50), while the estimated recovery factor with only vertical wells is 12%, indicating that the drilling recovery of horizontal wells is approximately 10% higher. The application of azimuthal tools has helped increase resistivity at the top of the Areniscas Basales Unit. 27 wells have been drilled with this technology, with a production peak of 17.5 thousand BOPD, for an average of 998 BOPD per well. The high rate of oil recovery from horizontal wells will increase production by 180 thousand BOPD. 3P reserves are estimated at 385 million STB oil. The completion ICD is in a preliminary stage of implementation with a pilot study of 3 wells. The performance of the wells during the first 6 months of production will be evaluated to define the use of ICD in critical areas of the site where the thickness is less than 20 feet. Using the experience gained during the last 5 years, during which 296 horizontal wells were drilled using the navigation plan designs and insights from production geology, reservoir engineering, drilling engineering, completion engineering and production engineering, improved performance and improved development costs of the Rubiales Field have been achieved. Acknowledgements The authors thank Ecopetrol and Pacific Rubiales Energy SA for permission to publish this document. They also acknowledge their geology and petroleum engineering colleagues for the ideas and concepts that they contributed to this manuscript. Nomenclature M = Thousand. MM = Million. STB = Stock-tank Barrel. B/D = barrels per day. BOPD = barrels of oil per day. F = Degrees Fahrenheit. TVD = True vertical depth. References. 1. Department of Petroleum Engineering Pacific Rubiales "Annual Technical Report - Participation Agreement rubiales 2011." Feb Department of Petroleum Engineering Pacific Rubiales "Annual Technical Report - Participation Agreement Pirirí 2011." Feb Pacific Rubiales Reservoir Management "Study of reserves Participation Agreement Rubiales year 2011." June Pacific Rubiales Reservoir Management "Study of reserves Participation Agreement Pirirí year 2011." June Tor Ellis et al: "Inflow Control Device-Raising Profiles" Oilfield Review Winter 2009/2010: 21, No 4. Schlumberger.

13 SPE APPENDIX A - Rubiales Field location in Colombia. APPENDIX B - Resistivity and petrophysical log - Rubiales Field.

14 14 SPE APPENDIX C - Areniscas Basales Unit correlaction Rubiales Field.