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Alshammari, Awadh T. (Petrofac, CCC – Consortium - Kuwait) | Alajmi, Haifaa M. (Kuwait Oil Company) | Marquez, Sharoh G. (Australian College of Kuwait) | Farhart, James L. (Worley Parsons Kuwait) | Al-Otaibi, Faisal S. (Kuwait Oil Company)
The cyclic steam stimulation (CSS) and injection process is a thermal recovery process consisting of three main stages: steam injection, steam soak and production of the heated oil. Before a stimulated well is put into production, a soak period is required to allow the injected steam to heat the oil around the wellbore and reduce its viscosity so that it will become more susceptible to flow. In actual operations, the soak period could vary from days to weeks, or even months. Prolonged soak period causes the well productivity to decline because of the continuous heat loss to the formation. On the other hand, insufficient soak period prevents effective transfer of the heat from the wet steam into the formation. For this reason, it is desirable to determine the optimal soak period that will maximize oil production and net profit during cyclic steam injection. The injection period at the beginning of the cycle, as well as its ensuing production period is also investigated to verify which stage in the CSS process is most influential in assuring higher recovery.
In this study, a thermal, numerical reservoir oil simulator is utilized to evaluate the effect of varying the injection volume, soak period and production period with a view to improving crude oil recovery in Ratqa-North Kuwait Lower Fars Heavy Oil (LFHO) reservoir. Further economic studies are then pursued to determine the effectiveness of cyclic steam injection operations whilst maintaining a safe operational environment ensuring cap-rock integrity and also avoiding localized pockets of higher pressure and temperature (heaving).
The key findings from this study was that the maximum injection period (60 days), minimum soak period (5 days) and minimum production period (90 days) are required for every cycle, in order to maximize recovery and optimize the cost.
The Bachaquero field is located on the east side of Lake Maracaibo, where oil exploitation has been occurring for more than 50 years. Primarily composed of sandstone, most of the producing reservoirs in this formation are from the Tertiary period and can be found in the Miocene Epoch. Nonconsolidated and poorly consolidated sands are also common in this field.
Complex mineralogy has been identified as the primary cause of production decline for wells in this field, with fines migration being the principal mechanism of formation damage. Other factors also influence the decline in production rate, including high-permeability formations, salinity, pH changes, and drag forces caused by fluid-flow velocity, multiphase flow, turbulence, and fluid viscosity.
Chemical stimulation has become a useful technique for enhancing production, and matrix acidizing with hydrofluoric-acid (HF) systems has proven to be very effective in this field. Matrix stimulation is a technique that has been used extensively since the 1930s to improve production from oil and gas wells and to improve injection into injection wells. Matrix stimulation is accomplished by injecting a fluid to dissolve and/or disperse materials that impair well production in sandstones or to create new, unimpaired flow channels between the wellbore and a carbonate formation. In matrix stimulation, fluids are injected below the fracturing pressure of the formation. Substantial production improvements can be achieved with matrix stimulation if treatments are engineered properly.
It is well known that HF reacts with clays present in the reservoir to dissolve them and restore original permeability, but some of those reactions are not always desired. Secondary and tertiary reactions of HF with aluminosilicates can promote nonsoluble fluorosilicates precipitation, which requires that fluids be tailored for compatibility with the formation's mineralogy. Variations in mineralogy determine which fluid performs better, and a high presence of feldspars requires more conservative treatments to avoid undesirable precipitations. A stronger retarded HF (RHF) has also been used to treat wells that are deeper in the formation.
Other good practices in addition to primary acid selection are also applied to help ensure treatment success. The stimulation treatment design includes pumping formation conditioning fluids before and after the main acid; using different types of organic solvents to dissolve asphaltene deposits in the well; performing NWB, HCl, and HCl/organic acid blend preflushes and post flushes to treat calcium deposits and control pH and iron precipitation in the reservoir; achieving short-term clay inhibition and long-term clay stabilization; and using other fluids, such as relative permeability modifiers (RPMs) for water-control applications and diversion of treatment in laminar reservoirs with petrophysical heterogeneities. Each of these combined practices have resulted in successful stimulation of the field.
This paper discusses a comprehensive approach that has been successfully applied in wells located in the Bachaquero field in the Maracaibo basin. The workflow includes a candidate analysis, from the reservoir description, mineralogy, and identification of the formation damage mechanism, to stimulation treatment design, laboratory fluid-systems tailoring, placement and diversion techniques, pretreatment operational task fulfillment, field execution, quality control, and post-job evaluation through analysis of records and statistics.
A new workflow for fracture prediction and modelling based on geological time-step DFN has been used to better constrain the fracture distribution and timing of generation in the Motatan Domo Sur field of Venezuela. Using the Fault Response Modelling module in Move™, simulations of fracture generation under two tectonic transpressive events with SHmax of 280° and 310° were modeled to find the best-fit fracture forming event as compared with the observed data. These events are of Paleocene-Eocene and Miocene age, respectively. This workflow includes a DFN built from borehole images of five wells whose fracture properties are spatially modeled taken into account structural and petrophysical indicators of sub-surface fracture systems. A comparison between measured and modeled fractures is discussed to evaluate the influence of each tectonic event.
Modeling the location of discontinuities (faults and fractures) in the subsurface associated with a given tectonic event requires a geomechanical model, which incorporates stress boundary conditions and mechanical properties. In this paper, we outline a new workflow which allows fracture forming events to be simulated and used to predict fracture distributions across reservoirs; the results of these simulations can supplement petrophysical, geomechanical and subseismic indicators to produce more representative fracture models. This workflow is applied to the south dome of the Motatan reservoir, which is located in the tectonically complex Maracaibo basin of Venezuela.
This workflow consists of two phases: 1) the building of present day discrete fracture network (DFN) through the integration of petrophysical, geomechanical, structural and subseismic indicators of fracture systems (e.g. curvature and bore hole image data); and 2) the simulation of slip on faults, calculating the resulting strain field and comparing predicted fracture orientations for different tectonic events with the observed fractures. The combination of these two phases provides a better understanding of natural fracture systems and provides information about the development of reservoir fracture systems through time.
Oil exploitation in the Bachaquero field in east Maracaibo Lake has been occurring for more than 50 years. Sandstone is the primary formation type, and nonconsolidated and poorly consolidated sands are common in this field. Complex mineralogy and fines migration have become root causes of production decline and formation damage. This paper describes a comprehensive approach to reservoir characterization that has contributed to the successful stimulation of the sandstone formations in the field.
Chemical stimulation, specifically matrix acidizing with hydrofluoric (HF) acid systems that are customized and tailored to reservoir characteristics, has proven to be effective at enhancing production in this field. The types of clays that are present include kaolinite, illite, smectite, chlorite, and mixed-layer clays; feldspars are also present. An adequate analysis of each well helps to ensure that HF acid dissolves the clays to restore permeability without promoting nonsoluble fluorosilicates precipitation through reactions with aluminosilicates. Variations in mineralogy determine fluid performance and make customized fluid selection necessary. The high presence of feldspars requires more conservative treatments to avoid undesirable precipitations.
Reservoir characterization and fluid tailoring has helped ensure treatment success, but other good practices also have been applied to help achieve production goals. The stimulation treatment design includes pumping formation-conditioning fluids before and after the main acid; using different types of organic solvents to dissolve asphaltene deposits in the well; performing near-wellbore (NWB), hydrochloric (HCl) acid, and HCl/organic acid blend preflushes and post-flushes to treat calcium carbonate and control the pH and iron precipitation in the reservoir; achieving short-term clay inhibition and long-term clay stabilization; and using other fluids, such as relative permeability modifiers (RPMs) for water-control applications and diversion of treatment in laminar reservoirs with petrophysical heterogeneities. All of these combined practices have resulted in successful stimulation of the field.
This paper discusses in detail this comprehensive approach to reservoir characterization applied successfully in wells in the Bachaquero field. The workflow includes candidate analysis, from reservoir description and mineralogy and formation damage mechanism identification to stimulation treatment design, laboratory fluid systems tailoring, placement and diversion techniques, pretreatment operational task fulfillment, field execution, quality control, and post-job evaluation through analysis of records and statistics.
Low-density water-based drilling fluids formulated with hollow glass spheres (HGS) offer an attractive drilling method. HGS are incompressible lightweight additives with the capability to reduce mud weight down to 41.0 lbm/ft3 (5.5 lbm/gal). Several pressure ratings of HGS are available, and selecting the appropriate rating is essential to avoid formation damage and lost circulation in near-balance conditions. Failure of the spheres could thus lead to catastrophic results.
The objectives of this paper is to evaluate the stability of inhibited water-based drilling fluids formulated with HGS in diverse pH environments, and assess their potential application in Wasia formations in Saudi Arabia. Wasia formation is composed of middle cretaceous clastic rocks with layers of sandstone, shale and occasional limestone. Wasia is an aquifer with a thick unit that crops out in central Najd with a slight eastward dip (
We conducted comprehensive analysis of HGS performance in various pH environments to assess their stability in drilling fluids. Mud characteristics and rheological properties were examined before hot rolling (BHR) and after hot rolling (AHR) to determine the effects of high pressure and high temperature (HPHT) on the system. The duration at which the samples were exposed to HPHT conditions varied from 1 to 4 days to understand the behavior of the mud over time. In addition, two typical formulations were prepared using HGS and conventional additives to evaluate their properties and compare them to the American Petroleum Institute (API) standards.
Hollow glass microspheres were found to be stable in the pH conditions of drilling operations (pH ~9), with a maximum density variation of 0.5 lbm/ft3. At higher pH levels (pH >11), the spheres experienced fractional dissolution due to the reaction of the added NaOH with borosilicate glass. In pH ranges lower than 4, the spheres were found to be extremely stable. The inhibited water-based fluids formulated with HGS produced favorable rheology and stable mud characteristics before and after exposure to the actual downhole temperatures of Wasia formation.
Waterflooding is an improved oil recovery (IOR) method commonly used worldwide. Some of the world's largest waterfloods are found on Lake Maracaibo, in western Venezuela. One such project is the Bachaquero-02 (Bach-02) which was initiated in 1967 as a peripheral water injection in an unconsolidated sandstone reservoir with average permeability of 350 mD and average oil gravity of 15 API. This waterflood project has been the subject of various studies that include conventional assessments, integrated full field and simulation studies. This paper presents a diagnosis of the impact that waterflooding has on Bach-02 heavy oil recovery, in view of a new approach that reveals mechanisms of heavy oil displacement by water. The findings of this field study are in accordance with empirical, experimental and simulation investigations recently reported in technical literature. Voidage Replacement Ratio (VRR) and Water Oil Ratio (WOR) analysis in this reservoir show particular behaviors associated with fluid flow characteristics in the reservoir; namely, periods of VRR less than 1.0 which activate mechanisms that stabilize WOR at values close to 1.0 and result in increased oil recovery. These mechanisms are explained by recent investigations as the flow of water-in-oil emulsions, and in situ formation of foams that benefit from chemical changes brought about by periods of underinjection.
Tinoco, Jose (Schlumberger) | Celis, Criss (Schlumberger) | Lopez, Luis (Schlumberger) | Rodriguez, Ernesto (PDVSA) | Coronel, Gustavo (PDVSA) | Lopez, Jose (a Schlumberger company) | Bits, Smith (a Schlumberger company)
The history of La Ceiba field began 10 years ago when six exploration wells were drilled to assess the potential of this field. The wells were drilled with several incidents of stuck pipe and the resulting necessary sidetracks to reach the final depth. Until last year no further attempt had been made to drill in this field. With little information available from the exploration wells concerning drilling practices, the drilling campaign began with the goal of improving the previous performance, making the drilling of the complete wells faster and safer than in the previous drilling. An engineering process was begun to find the best drilling solution for the field, starting with proven technologies such as positive displacement motors (PDM) and drill bits used in similar fields; however, this methods alone were not sufficient to meet the challenges of the field. New technologies were used for the different challenges and applications through coordinated work between the drilling engineering departments of the different parties involved in this field and using all the information available in the drill bit selection database, including logs and stability data for the tools selected to drill each phase of the wells. With evolution of the learning curve, drilling progressed from initial drilling involving 12 runs with time-consuming trips to surface to change either the drill bit or PDM, to drilling the same interval in 5 runs with the time on bottom increasing compare to previous experiences due to the introduction of tools more suitable to the environment requirements a rotary steerable systems (RSS) in combination with a specially designed drill bit. Problems commonly faced in the upper sections were, the trajectory was not strictly followed, were solved with the introduction of the RSS in this section; use of the tool saved 10 days of rig time and set a bench mark for the field and similar wells in western Venezuela. The development of this field shows that by solving the issues related to the well depth, temperature and constraints well design for these wells in western Venezuela, it will be possible to reach the oil reserves, at the same time decreasing the time spent in the drilling process. 2 SPE-169428-MS
Major heavy oil accumulations are found in the tertiary sandstones of the Lagunillas Formation of the Costanero Bolivar Field, located in Lake Maracaibo, Venezuela. The hydrocarbons are found in poorly consolidated shaly-deltaic sands, at depths of around 1200 ft to 2350 ft. The oil ranges from 10 to 18 degrees API, with viscosities ranging from 400 cP to 10000 cP. The formation water salinity is below 5000 ppm and variable within the reservoir, after years of injection of fresh water and steam to increase recovery. Consequently there is today no correlation between water cut and resistivity and the differenciation between oil and water with conventional petrophysical techniques is inaccurate. Conventional log analysis has limited potential since the resistivity shows identical values in both oil and water bearing levels.
Deciding on a completion strategy from an inaccurate saturation computation is a major challenge. Additionally, the free water presence reduces the net pay and rapidly increases the probability of water production in this high oil viscosity environment. Therefore an accurate assessment of free water and oil viscosity is a critical factor in the economics of the field. The present work incorporates dielectric and molecular diffusion measurements, showing significant progress in detecting free water from oil and defining the most prospective intervals.
Movable oil and fresh water are clearly identified using dielectric polarization at multiple frequencies. The dielectric measurement provides the water-filled porosity, while the magnetic resonance identifies the irreducible versus free water within that volume. This allows predicting the likelihood of producing hydrocarbon or water in areas with high oil saturation. In conclusion, the integration of dielectric polarization and diffusion information at multiple depths into the reservoir enable to distinguish oil from free and bound water and to estimate the oil viscosity, a result impossible to obtain with conventional logs in these environments. This integrated methodology allows accurate reservoir characterization and definition of the production potential of these heavy oil sands, leading to improved completion decisions.
The development campaign in Lagunillas sands now has a new workable technique to reduce uncertainties and to optimize heavy oil production.
The exploitation and development of large heavy and extra heavy oil fields in Venezuela represents one of the largest hydrocarbon accumulations in the world. These deposits can be found at the Orinoco Heavy Oil Belt in Eastern Venezuela, the Bolivar Coast Fields in Western Venezuela and Santa Barbara and Pirital Fields in the Northeast of Venezuela. The Orinoco Heavy Oil Belt represents a 90% of the discovered extra-heavy oil in the country.
Enormous deposits of hydrocarbons can be found in "Cerro Negro??, "Machete??, "Hamaca?? and "Zuata?? that belong to the Orinoco Heavy Oil Belt. These fields contain extra-heavy crude of 8 to 9 oAPI, an oil viscosity of 8,500 cp, an original depth of 2,900 ft and a thickness of 217 to 287 ft. The sand depositional environments are originally fluvial or deltaic and laterally discontinuous.
Santa Barbara Field contains heavy oil crude of 16 to 19 oAPI, an oil viscosity of 510 cp, a depth of 200 to 1,150 ft and sand thickness of 40 to 253 ft. The fields come from delta derived sandstones enviromentals. Bachaquero, Lagunillas and Tia Juana Fields in the Bolivar Coast Field contain heavy crude of 11 to 15 oAPI, viscosity of 100 to 10,000 cps, depth of 1,000 to 3,000 ft and sand thickness of 50 to 300 ft. The sand consists of non-marine sediments, eventual transgressions and conglomerate sandstones depositional environments.
The fields were studied to extract information about successful application and evaluation of cyclic steam stimulation (CSS). In the Northern part of Tia Juana Field where the viscosity was higher than expected (typically 20,000 cp), a steam assisted gravity drainage (SAGD) Pilot was implemented. Statistical analysis allowed the quantification of the parameters that affect the incremental recovery factor. As a result, it was found that the basic controls are oAPI, viscosity, depth, thickness and well spacing.
Thermal recovery processes are mainly applied to deposits less than 1,100 m of depth, oil viscosity greater than 50 cp, gravity less than 20 oAPI and typical well spacing of 2-5 acres. The most common applied method was cyclic steam stimulation (CSS) with a positive incremental of oil-steam ratio, from 1.5 to 6.8. Steam Assisted Gravity Drainage (SAGD) in horizontal wells was applied increasing significantly the recovery efficiency, higher than 50%.
Techniques for constraining rock compressibility magnitude can aid in reducing uncertainty associated with reservoir flow and well operability prediction when core recovery issues dictate that such geomechanical analyses must be performed without the luxury of laboratory testing. An extensive database of uniaxial strain pore volume compressibility "Cf" measurements has been compiled for diverse siliciclastic reservoirs ranging from unconsolidated sands to tight gas sandstones. We observe that: (i) elastic stiffness determined from unloading back to pre-production, initial reservoir stress conditions "IRSC" declines systematically from cemented to friable to unconsolidated formations in response to complex variation in microstructural parameters; (ii) the difference between "Cf" magnitude measured on loading versus unloading to "IRSC" is attributable to the irrecoverable (plastic) component of deformation which increases systematically as elastic stiffness decreases. Thus "Cf" at "IRSC" can be approximated from dynamic elastic moduli derived from acoustic wireline measurements following fluid substitution to simulate dry rock response. Subsequent "Cf" evolution with fluid pressure reduction "DPres" can be highly non-linear due to shearenhanced compaction and pore collapse. Finite element modeling has been used to iterate on elastoplastic material parameters describing the Cam clay constitutive model until a best-fit with experimentally derived "Cf" versus "DPres" response is achieved. Cam clay material parameters exhibit distinct lithotype-dependent trends that potentially enable their prediction from wireline measurements without recourse to core testing.
Reservoir pore volume compressibility (oftentimes referred to as formation compressibility, "Cf") is a fundamental rock property utilized in many reservoir engineering calculations including reserves estimates, reservoir performance and production forecasting . "Cf" dictates the magnitude of pore volume strain associated with declining fluid pressure resulting from production. As typical values in oilfield units range from ~1E-6 < Cf (1/psi) < ~100E-6 for each million barrels of reservoir pore space a reduction of between 1 and 100 barrels would result for every "psi" decrease in fluid pressure, where 1psi = 6.8948kPa. Porosity reduction controlled by "Cf" contributes to pressure maintenance and therefore enhances fluid production. For example, in the Bachaquero field in Venezuela, half of the production was attributed to compaction drive  however reservoir compaction due to fluid withdrawal can also result in significant permeability impairment . "Cf" can only be accurately quantified via geomechanical measurements on recovered core in which care is taken to simulate in situ stress magnitudes and boundary conditions . In undersaturated reservoirs (fluid pressures in excess of the bubblepoint) liquid and formation compressibilities represent significant proportions of the total compressibility of the reservoir system. While fluid properties are generally well constrained, pressure decline above the bubblepoint can be very rapid such that a substantial amount of recovery can occur prior to obtaining core and measuring mechanical properties. To accommodate this need for rock property data early in the production lifecycle a technique for predicting "Cf" from geophysical wireline logs offers considerable advantage. Further, discrete core measurements are rarely obtained in sufficient number to overcome between-sample data variability.