Microfracturing is an excellent method of obtaining direct, in-situ stress measurements, not only in shales, but in conventional reservoirs as well. Recent advances have shown that microfracturing can help improve reservoir management by guiding well placement, optimizing injection rates, and managing perforation strategy.
Microfracturing consists of isolating small test intervals in a well between inflatable packers, increasing the pressure until a small fracture forms and then by conducting a few injection and shut-in cycles, extend the fracture beyond the influence of the wellbore. Results show that direct stress measurements can be successfully acquired at multiple intervals in a few hours and the vertical scale nearly corresponds to electric log resolution. Therefore, microfracture testing (generally performed in a pilot / vertical well) is an appropriate choice for calibrating log derived geomechanical models and obtaining a complete, accurate, and precise vertical stress profile.
This paper describes the microfracturing process and presents several examples that led to increased hydrocarbon recovery by efficient stimulation and/or completion design. Case studies presented range from optimizing hydraulic fracturing in unconventional (Delaware Basin, USA), determining safe waterflood injection rates in brownfields (Offshore UK), and helping improve perforation placement in ultra-deepwater reservoirs.
Since the sequence of geological formations penetrated whilst drilling have different pore and fracture pressures as well as characteristics, the well cannot be drilled in one section to total depth. The cost of the casing strings represent approximately 20-40% of the total well cost. Additionally, running and cementing the casing consume rig time adding additional costs to the well. The Reelwell Drilling Method (RDM) is a new method developed and tested that is based on the use of a Dual Drill String (DDS) where the drilling fluid flows to the bit via the drill string annulus, and the return flow carrying cuttings to the surface is through an inner pipe as the annulus is sealed off using a Rotating Control Device (RCD) atop the Blow Out Preventer (BOP). With this unique flow arrangement, nothing is flowing in the annulus.
Al-Daghar, Khadeeja A. (SPE) | Atfeh, Mudar M. (SPE) | Aal, Atef F. Abdel (Abu Dhabi Company for Onshore Operations (ADCO)) | Jain, Vikas (SPE) | Murray, Doug R. (SPE) | Minh, Chanh Cao (SPE) | Gzara, Kais (Schlumberger)
Fluids saturations in new wells are usually derived from resistivity measurements, using locally selected or calibrated resistivity equations. Some drawbacks to resistivity measurements are multiple environmental corrections in high-angle wells, thin beds, washed-out boreholes, and complex invasion profiles. Moreover, the accuracy of Archie's equation may suffer from variable cementation and saturation exponents and unknown water salinity.
A recently introduced comprehensive suite of consonant logging-while-drilling (LWD) nuclear measurements with linear mixing laws, is used to solve for minerals and fluid volumes independent of resistivity measurements. This requires the petrophysical properties of all the fluids present to be known. Another requirement for accurate formation evaluation is the mud filtrate invasion correction. While this poses no problem for multiple depths of investigation (MDOI) resistivity measurements that also read deep into the formation, there is no set rule to determine the geometrical factor of nuclear measurements to account for invasion.
This paper describes an LWD time-lapse data acquisition scheme to circumvent invasion effects on nuclear measurments and to eliminate the need to specify some of the unknown petrophysical properties of the fluids present. Canonical-correlation analysis (CCA) is used to identify canonical variates that remain unchanged between a primary drill pass and a secondary wipe pass. Because these variates remain unchanged between passes, they are independent of the formation invasion status, and can represent the properties of either the virgin or the flushed zone, but not a combination of the two, as is typically the case of measurements whose volume of investigation samples both zones. These invasion-independent variates are then used in the petrophysical evaluation, instead of the standard logs which may otherwise vary with time.
We used CCA in 2 carbonate examples to show how to 1) correct bulk density measurement in corkscrew borehole, 2) correct MDOI capture sigma measurements for invasion effect, and 3) perform volumetric formation evaluation without knowledge of the water and hydrocarbon endpoints and invasion parameters. The CCA approach is a significant new development in well log interpretation that removes uncertainties associated with unknown mineral or fluids petrophysical properties and invasion status.
AL-Ameri, Wahbi Abdulqader (SPE) | Abdulraheem, Abdulazeez (SPE) | Mahmoud, Mohamed (SPE) | Abdullatif, Osman (King Fahd University of Petr. & Min., Dhahran, Saudi Arabia, in partnership with King Abdul-Aziz Center for Science and Technology-Technology Innovation Center on Carbon Capture and Sequestration) | Adebayo, Abdulrauf Rasheed (King Fahd University of Petr. & Min., Dhahran, Saudi Arabia, in partnership with King Abdul-Aziz Center for Science and Technology-Technology Innovation Center on Carbon Capture and Sequestration)
The long-term geological sequestration of carbon dioxide (CO2) in underground formations (deep saline aquifers) is the most economically viable option to decrease the emissions of greenhouse gas in the atmosphere which are the main contributing factors for global warming. The injection of CO2 in carbonate aquifers dissolves some of the calcite rock due to the formation of carbonic acid as a result of the interaction between CO2 and brine. This rock dissolution may affect the rock integrity and in turn will affect the rock mechanical properties. The effect of CO2 on the rock mechanical properties is a key parameter to be studied to assess the aquifer performance in the process of geological sequestration and to get safe and effective long-term storage.
The main objective of this study is to address the impact of geological sequestration of CO2 on the mechanical properties of carbonate aquifer and cap rocks. In addition, the effect of the storage time on these properties are investigated. Moreover, the effect of CO2 sequestration on rocks with different mechanical properties are studied, and the good candidate carbonate rocks for geologic sequestration are identified. In this study the CO2 was injected and soaked with the brine with the core at high pressure and high temperature (2000 psi and 100°C) to simulate the actual downhole conditions The carbonate cores were analyzed for mechanical properties using indirect tensile strength, unconfined compression, and acoustics testing machines.
Results show that CO2 sequestration affected the mechanical properties of the carbonate rocks as well as the cap rocks. Long time soaking of CO2 in brine allowed for the formation of enough carbonic acid to react with the cores and this greatly impacted the rock mechanical and acoustic properties. The significant impact of CO2 storage was noted on Khuff limestone and the good candidate among the carbonate rocks studied here for geological sequestration of CO2 is found to be Indiana limestone.
During the past years, Brazil has been experiencing a significant oil boom, mainly due to its successful and technologically challenging deep offshore exploration campaign, namely the "pre-salt" area. Furthermore, after a five-year halt on bidding rounds, Brazil held two bidding rounds last year: one aimed at on-shore unconventional exploration, as an attempt to stay current on the abroad shale revolution, the other being the first pre-salt PSC bidding for the super-giant field of "Libra". In fact, Brazilian authorities have stated that they expect to nearly double its domestic production within the next five years [
Both of these exploration frontiers represent not only innumerous financial, technological and logistical challenges, but the success will be dependent and profoundly driven by the availability of the country's petroleum-industry workforce resources involved; specifically, its ability to supply the sudden and critically arising demand. In addition, turning the scenario even more complex is the fact that Brazilian law [
In face of such a scenario, the SPE Brazil Section, along with several nation-wide company and university representatives, developed and proposed a new unified petroleum engineering program course, aimed at all Brazilian universities. It is on such report that this paper is based.
The extensive report indicates that existing academic programs must undergo some changes, if they are to adapt to modern industry requirements and standards. For instance, it concluded that only one-third of a program should be composed of basic courses, with more than half of them on specific-petroleum-oriented courses, together with one-tenth on professional-applied courses. In summary, the report indicates that the Brazilian approach on scientific education must be improved and re-thought, combining a theoretical approach and practical considerations.
Al-Weheibi, I. (SPE) | Al-Hajri, R. (SPE) | Al-Wahaibi, Y. (SPE) | Jibril, B. (Petroleum and Chemical Engineering Department, Sultan Qaboos University, Oman) | Mohsenzadeh, A. (Petroleum and Chemical Engineering Department, Sultan Qaboos University, Oman)
This study investigates the potential of chemical solvent called deep eutectic solvents (DES) to recover the residual heavy oil left after waterflooding. For the first time to our knowledge, the effectiveness of two DESs - choline chloride-malonic acid of molar ratios 1:1 and 1:0.5 - in enhancing heavy oil recovery was thoroughly investigated. As preliminary investigations, the two solvents were characterized by measuring density, viscosity, conductivity and pH at different temperatures (20 - 80 C). In order to investigate the EOR potential of the solvent, measurements of interfacial tension, wettability alteration, spontaneous water imbibition, emulsification, core flood and formation damage tests were conducted at different temperatures. The core flood test was carried out at reservoir condition (pressure 1200psi, temperature 45 - 80 C) using Berea sandstone core samples and fluids from the field of interest (formation brine and crude oil). Results of the core flood test showed the solvents produced 7-14% of the residual heavy oil after brine flooding as tertiary recovery stage and both DESs displayed better performance in enhancing the oil recovery at higher temperatures. Measurements of absolute permeabilities before and after injection of DESs/brine solutions showed no damage to the formation. Wettability alteration was found to be the dominant mechanisms for the tertiary oil recovery enhancement.
As expansion into unconventional reservoirs continues, one of the key drivers of well performance has become completion efficiency. Much of this efficiency centers around finding the completion strategy that effectively drains the entire lateral in a horizontal wellbore. Different fracture spacing and perforation schemes have been attempted to try and accomplish maximum coverage with minimal interference between stages. However, even as fractures are planned with a particular spacing, there is no guarantee that every perforated interval will lead to a productive fracture. One of the key questions has been: How many of the fractures are actually contributing to production? Numerous authors have developed methods for estimating this number, and a small set of diagnostics tools are currently being used in the industry to evaluate fracture placement.
Cozyris, K.M. (Baker Hughes) | Churcher, P.L. (Lighthouse Oil & Gas Canada Management Inc.) | Piland, J.R (Lighthouse Oil & Gas LP) | Maharidge, R.L. (SPE) | Adamson, M.D. (SPE) | Lew, R. (Baker Hughes)
The effective optimization of fracture stimulation treatments in horizontal wells requires the integration of a wide range of engineering and geological data to be successful. This process begins with a thorough understanding of not only the reservoir rock properties, but also the properties of the confining nonreservoir rock. This geological information is used in the design of non-damaging completions fluids, to predict the fracture height growth and fracture half length, and to interpret the results from diagnostics, post job stimulation data and production performance. This paper documents the work conducted to design and implement multistage horizontal fracture stimulations in the Cleveland and Tonkawa sandstones located in Dewey County, Oklahoma. Methods used in this process included: 1) review of historical treatment and production data available in the area to help identify current best practices, 2) SEM, thin section and X-ray diffraction petrography to define the mineralogy, 3) core floods to determine formation damage mechanisms, 4) laboratory proppant pack floods to screen for the effectiveness of chemical additives (such as surfactants), 5) core floods using reservoir rock to determine regain permeability and flow back performance, 6) determination of mechanical rock properties, such as Young's modulus, Poisson's ratio, Brinell hardness and triaxial stress, from multiwave sonic and laboratory testing for use in fine-tuning the fracture stimulation model parameters, 7) design, acquisition and analysis of initial injection and falloff tests, 8) fracture stimulation modeling to predict the fracture geometry created by the fracture design, and 9) analysis of hourly flow back and tracer data to determine the effectiveness of the treatments in accessing the maximum amount of reservoir rock. The objectives of this work were to engineer an optimized treatment design (that would result in significant gains in initial well productivity and long term ultimate hydrocarbon recovery) and also to develop and refine new potential best practices.
In laminated clastic reservoirs, the difference in permeability at the bed scale could be several orders of magnitude across the various facies. In addition, cross-bedding and pinched-out geological surfaces give rise to tortuous flow paths. Incorporation of such flow-relevant fine-scale heterogeneities into reservoir-scale models is accomplished through an effective two-stage multiphase upscaling technique. The two stages of scale-up involve (1) bed to genetic-unit scale upscaling and (2) genetic-unit to reservoir scale upscaling. In the bed to genetic-unit scale upscaling step, full tensor permeabilities are computed using a fast flow-based upscaling procedure taking advantage of a multipoint flux approximation method. A novel iterative quasi-global pseudoization method is used in the genetic-unit to reservoir scale upscaling process. The fundamental idea of iterative pseudoization relies on the calibration of effective properties that govern coarse-scale flows to non-local regional interwell-scale flows in the underlying fine-scale model. The calibration is performed through the minimization of an objective function that computes the mismatch in flow responses between fine-scale and coarse-scale models. The pseudoization procedure is formulated as a constrained optimization problem, which is iteratively solved by estimating the variables that parameterize the pseudo-relative permeabilities and pseudo-capillary pressures.
The effectiveness of the two-stage upscaling technique is demonstrated in an intuitive example case featuring the scale-up of a stratigraphically complex Aeolian outcrop-scale reservoir-sector model for a waterflooding scenario. This proof-of-concept example is designed to validate the accuracy and efficacy of the two-stage upscaling method where the full-detail two-dimensional fine-scale model is affordable to simulate and serves as the “true” model for verification. Results indicate that the two-stage upscaling method renders practically intractable high-geologic resolution simulation problems tractable and delivers good accuracy.
Thermal compositional simulation can be challenging when narrow-boiling behavior is involved. The term “narrow-boiling” is used in the literature to refer to enthalpy that is sensitive to temperature. This paper presents an analysis of narrow-boiling behavior on the basis of multiphase isenthalpic-flash equations, where energy and phase behavior equations are coupled through the temperature dependency of K values. The Peng-Robinson equation of state is the thermodynamic model used in the analysis.
The general condition for narrow-boiling behavior is that the interplay between energy balance and phase behavior is significant. This is realized in engineering computations, such as flash calculations and reservoir simulation, as the sensitivity of K values to temperature. Two subsets of the condition are derived by analyzing the convex function whose gradient vectors consist of the Rachford-Rice equations; (i) the overall composition is near an edge of composition space, and (ii) the solution conditions (temperature, pressure, and overall composition) are near a critical point, including a critical endpoint. A special case of the first specific condition is the fluids with one degree of freedom, for which enthalpy is discontinuous in temperature.
Case studies are given to confirm the narrow-boiling conditions for water-containing hydrocarbon mixtures. Narrow-boiling behavior tends to occur in thermal compositional simulation likely because water is by far the most dominant component in the fluid systems formed in the simulation. K values can be sensitive to temperature for those fluids with skewed concentration distributions. Decoupling of temperature from the other variables is confirmed to be robust in isenthalpic flash for narrow-boiling fluids.