In order to get a full petrophysical evaluation from log-based traditional techniques in every location, the formation density is needed in wire-line log measurements; otherwise, with a limited amount of information in terms of porosity values, the reservoir characterization has more uncertainty. That is, the case study of the giant Bachaquero-02 reservoir, there is a lack of Rhob data in the spatial data sets that prevent a good assessment of the storage capacity in the petrophysical model and thus wrong original oil in place estimation. This paper, therefore, presents a solution to this problem; this work develops a methodology for predicting formation density values which establish a link between probabilistic interpretations from multi-mineral solution and deterministic predictions from multiple linear regression with the main objective of seeking a mathematical expression which describes the best fit for the Bachaquero Member and Laguna Member in each location. The manner of estimating formation density can vary according to the available data in well logs, as a first step, this technique uses classic lithology indicators from well logging such as gamma ray, spontaneous potential and resistivity index to calculate the most probable minerals in the rock with the purpose of assessing a probabilistic approach, the second stage is to create a prediction model with surrounding wells, the input data, which is the probabilistic outcome and measured logs, it is trained using a'least squares' regression routine that will find the best fit in the data for bulk density reckoning. A reliable formation density profile according to the lithology of the reservoir was obtained for each well. The model shows more than 0.9 of correlation coefficients between the density measured by wire-line services and the new bulk density reproduced in this method. Particularly, the Bachaquero-02 reservoir has a notorious heterogeneity along the stratigraphic column; the Bachaquero Member has different depositional environment and rock properties in comparison with Laguna Member which has poor quality reservoir rock. This workflow has the ability to incorporate reservoir heterogeneities in the probabilistic module without a problem. 2 SPE-191163-MS
The first recorded deliberate attempt to stimulate recovery from an oil reservoir by hydrocarbon gas injection was in the Macksburg field, Washington County, OH, ' long before water injection was used for secondary recovery purposes. For almost 60 years, most secondary recovery projects included some form of immiscible gas injection, and its use continued even after the advent of new methods and materials. In spite of this, it was the late 1940's before serious attempts were made to develop quantitative techniques for describing reservoir performance under gas-injection operations, especially with regard to depleted oil reservoirs. Before then, such efforts were directed primarily toward describing the water displacement process. As a result, techniques used to describe the performance characteristics of immiscible gas injection consist of modifications to methods originally developed for describing performance of water-injection operations, even though there is a fundamental difference in the basic displacement mechanisms of the two fluids.
Once an oil exporter, California now depends on imports for more than 60% of its oil supply. This paper examines the oil production outlook for each of California's major oil sources, including California itself. Oil production trends, published geological and engineering reports, and proposed developments in California's supply area are reviewed to define supply trends, especially for the medium-to-heavy, sour crudes that are processed in California's refineries. Refinery upgrading capacity is already highly developed in California, thus it is assumed that a competitive advantage in heavy, sour crudes will continue, although refining heavy oil releases more carbon dioxide.
About a quarter of California's imports are from Alaska, the rest from foreign sources including Saudi Arabia, Ecuador and Iraq. Before foreign sources became so important, California's refining industry processed California's own crudes and Alaska's North Slope crude. Like those crudes, oil from northern Saudi Arabia, southeast Iraq, and Ecuador is also sour and medium to heavy, ranging from 16 to 35° API and from 2 to more than 3% sulfur by weight. By far the most important sour crude development in California's supply area is Saudi Arabia's 900,000 BOPD Manifa project, originally slated for completion in 2011 but now facing delays. Manifa contains oil that ranges from 26 to 31° API and from 2.8 to 3.7% sulfur. Over the longer term, Alaska will continue to play an important supply role if the Chuckchi and Beaufort Seas live up to expectations.
Middle East production is not increasing, yet oil cargoes from the Middle East have to pass growing Asian markets to reach California. Alaska and Mexico also supply oil to the Pacific Basin, but are facing production declines. The effect of rising Asian demand on Pacific Basin oil markets is already visible, with significant amounts of oil coming to California from Atlantic Basin sources such as Angola, Brazil, and Argentina.
The US West Coast pipeline system is separate from the integrated East Coast, Gulf Coast and Midwest system, so energy security issues for the West Coast may differ from those of the country as a whole. There are policy options that could affect California's oil supply security, including increased oil development in Alaska or offshore California, development of additional oil pipeline outlets on Canada's Pacific Coast or substituting natural gas for oil if possible. All of these policy options are currently the subject of political debate.
Historical Oil Production Trends in California's Supply Area
Historical oil production trends are of interest because, unlike reserve estimates, they are readily verifiable factual information. Another issue with published reserve data is the quality of the supporting information; Alberta produces a detailed annual reserves report, while Saudi Arabia and Iraq publish only national aggregate figures. All of the oil production volumes reported in this section are from the annual production survey of the Oil and Gas Journal or the annual report of the Alaska Division of Oil and Gas and do not include natural gas plant liquids.
Iraq's oil production peaked in 1979 at 3.43 million BOPD. In 2007 it was 2.09 million BOPD, but production levels had been affected by internal instability and were higher in 2008.
Interactions of solid mechanics and fluid flow have been studied by numerous researchers for the past several years. Different methods of coupling such as full and iterative coupling have been used. Nevertheless, the accuracy and the large run time of the coupled solid-mechanics fluid-flow model are outstanding issues that prevent the application of the coupled model in full-field studies. In this work, a novel relationship of porosity as a function of pressure, temperature, and mean total stress is developed for iterative coupling of stress and flow. The new formula not only improves the accuracy of the coupling but also reduces substantially the number of coupling iterations. The latter feature decreases significantly the CPU time. The new approach was implemented in a modular, iteratively coupled system. The rapid convergence provides the equivalent of a fully coupled method that is necessary to investigate complex coupled problems. The main advantage of this type of coupling is that a geomechanics module can be easily coupled with different reservoir simulators. The paper gives some comparisons of results obtained by the new porosity formula with another formulation.
After 70 years of continuous exploitation in the Bolivar Coast region of Lake Maracaibo, Venezuela (Fig. 1), advanced reservoir depletion is causing drilling problems such as severe loss of circulation, hole instability, and extensive formation damage. In an attempt to optimize drilling performance, several operation practices were implemented through 1997, such as air-, mud-, foam-, and oil-base mud systems, etc., without achieving the expected success.
Because of the challenges of working in these mature fields, the operator and the oilfield services company created a services alliance contract called PRISA (a Spanish acronym for Integrated Drilling and Workover Alliance Services). This paper describes the drilling technologies and best practices used to improve drilling performance in these mature reservoirs, the learning curve evolution, and process improvement. The results included a cost reduction of 12% (in investment cost/barrel), a production increase of 4%, a 58.7% reduction in drilling time, and a drilling cost reduction of 3.6% (Figs. 2 through 3B). In addition, nonproductive time (NPT) has been reduced from 24.1% in 1999 to 3.8% in 2002 (Fig. 4).
In 1999 the operator entered into a 10-yr contract with an oilfield services company to drill and work over wells in mature areas of Maracaibo Lake. In this alliance the operator will share risks and involve the services company in the operations performance through an incentive-penalty scheme with the objective of reducing operation times and costs, protecting the environment, maximizing reserves recovery and introducing technologies to achieve the desired goals.
The engineers pooled their knowledge and expertise to build multipurpose green rigs designed for well construction and work over on Lake Maracaibo environment. Likewise, each rig has a sophisticated treatment system to recycle wastewater into water suitable for industrial use. The document presents how this system can avoid pollution and the wastes are sent onshore to be taken to a zone designated for their final disposal or recycling and the sophisticated system that these rigs have to operate with zero discharge of any pollutants in Lake Maracaibo.
The heavy-oil reservoir Bachaquero-01, in the Lagunillas district of Venezuela's Lake Maracaibo, has been productive since 1934. Because the oil gravity is only 12° API, steam has been injected since 1971 to increase production. To further optimize production, stand-alone horizontal wells have been drilled since 1996. However, in only 4 months after steam was injected into the horizontal wells, a very fast decline of up to 50[phone ] of initial production was observed in these nongravel-packed wells.
In a drilling-and-completion campaign from October 2000 to January 2001, 18 horizontal wells were successfully drilled and gravel-packed. In this paper we describe the gravel-pack techniques applied to minimize the rapidly declining rate of production in horizontal alternate steam-injection wells. We explain the method used for screen and gravel-size selection and summarize the completion operations and gravel-pack fluids that were used. We describe the modification of an existing hydraulic packer with a high-temperature seal of 600°F-a combination used for the first time worldwide. Finally, we illustrate the successful drilling-and-completion campaign with case histories and production performance.
The gravel-packed wells had an average increase of 15% productivity after 1 year with no sand production. The gravel-pack operations were executed at a pump rate of 2 to 3 bbl/min with a sand concentration of 0.5 to 0.7 pounds of proppant per gallon added (ppa), observing continuous fluid returns of 50% to 80%. The packers were successfully field tested after a period of three weeks of steam injection.
Advances in computing technology have allowed the development ofsophisticated 3D cellular modeling and visualization software, which has founda variety of applications in the oil industry. This technology includes spatialattribute modeling and the visualization of hydrocarbon reservoirs to improvethe understanding of the geological structure including internal features andthe distribution of formation properties.
This paper discusses experiences gained in building a geological model forthe LL-03 reservoir (in this reservoir there is a horizontal well drillingstrategy) and the subsequent manipulation and transfering of this data into a3D reservoir simulator for initialization purposes.
The paper covers the modeling of fault planes in complex reservoirs, thehandling of both vertical and sloping fault surface and the distribution ofpetrophysical properties (porosity, permeability and water saturation) of thegeological model to be used in the reservoir simulation.
The technique presented here differs considerably from the traditionalmethod for fault interpretation. This new method consists in interpreting theplane that describes the fault in the space, using several techniques thatallow defining the structural framework. Advantages for both, geocientists andreservoir engineers in displaying and reviewing the 3D image of the faultplanes and the reservoir at an early stage in the project are discussed.
The paper concludes with suggestion for developments of the workflow tocreate the most realistic fault plane according to the structural framework tofurther enhance the effectiveness of the present 3D modeling method.
The LL-03 reservoir is located in the Lake Maracaibo (Bolivar Coastal Field)and represents one of the biggest and oldest reservoirs of its northeasternregion. It occupies a lacustrine area of approximately 300 Km2, which includesLa Rosa, Punta Benitez, T a Juana and part of Lagunillas fields (figure1). It was discovered in 1925 by the exploratory well R-2, however thefirst production was reported in 1928. This production was from oil sands of LaRosa and Lagunillas Formations of Miocene age.
The LL-03 reservoir has more than two thousand wells that penetrated itsvertical section, of which 1051 wells have been completed and contribute with30% of the total production of the La Rosa Medium segregation of the MaracaiboDistrict. The production average in the year 2000 was 30 MBOPD, 1673 CF/NB and43% of water cut and sediments with an injection rate of 76.3 MBWPD.
The reservoir OOIP has been estimated in 6,9 MMbls. The primary and totalrecovery factors are 23.0 % and 24.5% respectively, with a remaining totalreserve of 124,885 MMbls.
The seismic survey COL-95B-3D was concluded during the second semester of1996 (figure 2), which allowed for the execution of several detailedstudies to define the structural and stratigraphycal aspects of severalreservoirs of the area.
At the moment, a 3D static model is under construction, which will be themain input to a process of numeric simulation and evaluation of future plansfor secondary recovery.
Interactions of solid mechanics and fluid flow have been studied by numerous researchers for the past several years. Different methods of coupling such as full coupling, iterative coupling, etc., have been used. Nevertheless, the accuracy and the large run time of the coupled solid-mechanics fluid-flow model are outstanding issues that prevent the application of the coupled model in full-field studies. In this work, a novel relationship of porosity as a function of pressure, temperature and mean total stress is developed for iterative coupling of stress and flow. The new formula not only improves the accuracy of the coupling, but also reduces substantially the number of coupling iterations. The latter feature decreases significantly the CPU time. The new approach was implemented in a modular, iteratively coupled system. The rapid convergence provides the equivalent of a fully coupled method that is necessary to investigate complex coupled problems. The main advantage of this type of coupling is that a geomechanics module can be easily coupled with different reservoir simulators. The paper gives some comparisons of results obtained by the new porosity formula with another formulation.
Reservoir simulation has a long history of development and it is used to model a wide variety of reservoir problems. However, using a conventional simulator still cannot explain some phenomena that occur during production such as subsidence, compaction, casing damage, wellbore stability, sand production, etc.1,2,3. Most conventional reservoir simulators do not incorporate stress changes and rock deformations with changes in reservoir pressure and temperature during the course of production. The physical impact from these geomechanical aspects of reservoir behavior is not small. For example, pore reduction or collapse leads to abrupt compaction of the reservoir rock, which in turn causes subsidence at the ground surface and damage to well casings. There are many reported cases of environmental impact due to fluid withdrawal from the subsurface. Well known examples include the sea floor subsidence in the Ekofisk field or Valhall field in the North Sea4; subsidence over a large area in the Long Beach Harbor, California5 or in the regions of the Bolivar Coast and Lagunillas in Venezuela6. In addition, production loss due to casing damage can be significant (e.g., in the Belridge Diatomite field in California7).
The fundamentals of geomechanics are based on the concept of effective stress formulated by Terzaghi in 19368. Based on the concept of Terzaghi's effective stress, Biot9 investigated the coupling between stress and pore pressure in a porous medium and developed a generalized three-dimensional theory of consolidation. Skempton10 derived a relationship between the total stress and fluid pore pressure under undrained initial loading through the so-called Skempton pore pressure parameters A and B. Geerstma11 gave a better insight of the relationship among pressure, stress and volume. Van der Knaap12 extended Geertsma's work to nonlinear elastic geomaterials. Nur and Byerlee13 proved that the effective stress law proposed by Biot is more general and physically sensible than that proposed by Terzaghi. Rice and Clearly14 solved poroelastic problems by assuming pore pressure and stress as primary variables instead of displacements as employed by Biot. Yet, all the above work has been limited to the framework of linear constitutive relations and single-phase flow in porous media. Rapid progress in computer technology in recent years has allowed the tackling of numerically more challenging problems associated with nonlinear materials and multiphase flow. Due to the complexity of the solutions of multiphase flow and geomechanics models themselves, the solution of the coupled problem is even more complicated and needs further study to improve accuracy, convergence, computing efficiency, etc. In particular, researchers have been debating which coupling approach is best for computing fluid-solid interactions. The term ‘interaction' is understood here as the mechanical force effect rather than the chemical reaction effect between fluid and solid.
The Lagunillas 07 reservoir is located Lake Maracaibo in Venezuela. The reservoir contains the Laguna, Lagunillas and La Rosa formations. The sands are of the Miocene age, poorly consolidated, well sorted and fine-grained. The oil had an 18° API and a viscosity of 21 cp at initial conditions. Oil production began in 1926 and more than 1,000 wells have been drilled. Flank waterflooding, at an average water injection rate of 100,000 stb per day, was introduced for pressure maintenance purposes in 1984. By December 1999, cumulative water injected was 558 million barrels and 36.7 % of the initial oil in place had been produced.
This paper evaluates the impact of the flank waterflooding project in the Lagunillas 07 reservoir. The net oil recovery due to the flank waterflooding is estimated. The real time water front movement is determined with a front-tracking technique that uses fluid production data. The movement shows water fingering due to reservoir heterogeneity. A good match is obtained when the water front movement is cross-correlated with the petrophysical properties of the reservoir. Finally, the impact of the flank waterflooding on recovery factor is highlighted.
The paper concludes that a net oil recovery of 17 million barrels can be attributed to the flank waterflooding from 1984 to 1999. A net oil recovery of 160 million barrels is expected if the flank waterflooding is continued until 2019. The flank waterflooding is therefore considered a success. A future development plan is proposed for the reservoir.
The Lagunillas 07 reservoir is made up of an arch structure with an average strike of 300° and a southwest dip of 3° to 3.5°. The average sand thickness is 86 ft. The reservoir consists of 3 units with cross flow and good vertical communication. The units are the Laguna, the Lagunillas Inferior and the La Rosa. The Laguna and the Lagunillas Inferior units consist of fluvio-deltaic sediments. There is sand continuity in both units. The Laguna unit pinches out to the northeast and is more complex with thinner, less continuous sands. The Lagunillas Inferior unit contains the best oil sands and accounts for about 90% of all initial oil in place. The La Rosa unit is mainly marine and is more heterogeneous with less oil sands.1
The first well was drilled in 1926. Early production data was of poor quality. Subsidence data were not taken until 1940 although surface subsidence due to rock compaction had occurred earlier. Rock property data were obtained from 2 core analysis studies. Average porosity was 30% and connate water saturation was 16%. The reservoir temperature was 152°F.
Field Production and Injection History
Oil production began in 1926 and reached a daily peak of 115,000 stock tank barrels (stb) per day in 1937. It fell to an average of 63,000 stb per day between 1938 and 1958 despite the installation of artificial lift to improve productivity due to pressure depletion. After 1958, the production rate became market dependent. It steadily declined to a low level of 16,000 stb per day in 1972. New infill wells were drilled and the oil production rate increased to 49,000 stb per day. The average reservoir pressure declined by more than 50% between 1926 and 1980. This decline prompted a study to determine the best pressure maintenance method.2 A flank waterflood was recommended by the study. The flank waterflooding was initiated in 1984. Figure 1 shows the daily oil production and the watercut. The watercut was in the 15% to 20% range between 1944 and 1984. It increased to 55% in 1998 as a result of the flank waterflooding.