Open Hole Section Research Articles

Performance of an open-loop well-doublet scheme located in a deep aquitard–aquifer system: Insights from a synthetic coupled heat and flow model

Understanding hydrothermal processes during production is critical to optimize geothermal reservoir operation and reduce the risk of its failure. The influence of the subsurface physical parameters, the design of the wells, and their operational settings on a high-enthalpy liquid-dominated geothermal operation has been investigated. For this purpose, a numerical model was developed, accounting for the flow, mass and heat transport in a single-phase aquitard–aquifer system, in the vicinity of a vertical 4-km well-doublet scheme. The sensitivity analysis varies the thermal power from 34.0 MWt to 58.1 MWt and the productivity index altered within the range 0–4.9 × 102 l s−1 bar−1. The parameters affecting both the hydraulic and thermal performances are (1) the reservoir permeability, (2) the injection temperature, (3) the production/injection rates, (4) the aquifer thermal conductivity, and (5) the length of the openhole section. These parameters provide a general control of the project and should be carefully estimated and designed. The predominant role of the aquifer parameters over the aquitard parameters is clearly demonstrated in this specific study. However, ignoring the caprock and bedrock in the model simulations would result in strongly and negatively biased estimates of the reservoir temperatures.

Reducing Costs of Well Plugging and Abandonment While Verifying Risk

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 27921, “Risk-Based Approach to Well Plugging and Abandoning: Reducing Costs While Verifying Risk,” by Pedram Fanailoo, David Buchmiller, Simon Ouyang, and Eric Allen, DNV GL, prepared for the 2017 Offshore Technology Conference, Houston, 1–4 May. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission. A risk-based approach to well plugging and abandonment (P&A) has been developed and successfully applied. The recommended method is based on research that allows the modeling of fluid flow through microcracks through a range of failure modes in downhole components, the determination of the effect on the environment through dispersion modeling, and identification of the basis for acceptance criteria. The complete paper describes how various P&A designs can be compared by use of a risk methodology that takes account of degradation mechanisms, potential flow rates, and the effect on the environment. Introduction The application of the proposed method to fields suggests that alternative plugging solutions with fewer barriers than prescribed by the standard NORSOK D-010 guidelines result in the same low level of environmental risk. The method accounts for uncertainty related to input parameters and can be refined further if these uncertainties are reduced over time by field observations and testing. The proposed approach to quantifying the environmental risk associated with minor, long-term leakage from P&A barriers, overburden formations, and natural seepage is to frame the issue in terms of potential modifications to valued environmental resources. This permits a degree of differentiation between alternative plugging designs, none of which may be physically capable of leading to the type of major leakage treated by standard environmental-risk-analysis approaches. Description of Well-Abandonment Designs General. Per NORSOK D-010, a P&A job should be planned and performed with an eternal perspective. Numerous regulations and requirements for different countries and areas of operation exist, but these generally state that there should be at least one permanent well barrier between a potential source of inflow and the surface. A potential source of inflow is defined in the guideline as a formation with permeability, but not necessarily a reservoir. This requirement does not apply to the case in which the formation is a reservoir, with a reservoir defined as a permeable formation or group of formation zones originally within the same pressure regime, with a flow potential or hydrocarbons present or likely present in the future; in this case, the requirement is two permanent well barriers. These requirements can lead to confusion because NORSOK D-010 does not provide any further explanation of the terms “in-flow” and “flow potential.” Some major operators define “flow potential” as a formation with permeability and over-pressure, meaning that a reservoir can be a formation containing hydrocarbons, a formation with permeability and overpressure, or a combination of both. Furthermore, NORSOK D-010 holds that the last openhole section of a wellbore should not be abandoned permanently without installation of a permanent well barrier, often known as the surface P&A barrier.

Optimizing Hole Cleaning Using Low Viscosity Drilling Fluid

When drilling for hydrocarbon, one most important thing to recognise is the bottom hole cleaning. Poor well hydraulics will lead to poor bottom hole cleaning. Several suggestions have been made in years back to prevent cuttings from falling to the lower side of the borehole thereby forming cutting bed. One of the main functions of drilling fluids is suspending the drill cuttings when the flow is static. But having met this criterion, cutting beds are still formed. The settling down of drill cutting makes this function of drilling fluid almost impossible. The formation of cutting bed due to the inability of the drilling fluid to establish this function brings about the objective of this research work. The main objective is to optimize hole cleaning using low viscosity drilling fluid and also to evaluate the effect of high flow rate on low viscous drilling fluid with respect to hole cleaning. This was carried out by a laboratory formulation of synthetic drilling fluid and the viscosity of this formulated fluid was varied from low to high. Tests for its rheological properties were carried out using Fann viscometer and the data obtained were recorded. The plastic viscosity and yield point were calculated from existing equations. The values for their rheological properties were tested using an existing hole cleaning model to determine the time taken for each of the drilling fluid to erode a 5 inches cutting bed. The fluid with an excellent hole cleaning value was also determined (CCI > or =1) and at optimum flow rate obtained for an 8-inches open hole section. When the values of their rheological properties were tested in the hole cleaning models, it was observed that, low viscosity fluids can erodes a 5 inches cutting bed height faster than the other drilling fluids and achieved an excellent hole cleaning value at an optimum flow rate when tested with the second model.

Hydraulic fracturing initiation and propagation in deep inclined open hole for Enhanced Geothermal System

This paper describes the development of a generic geomechanical model for estimating the fracture initiation in open hole section and the overall fracturing propagation during the hydraulic stimulation in Enhanced Geothermal System. General studies on the effects in situ stress and open hole trajectory on hydraulic fracturing indicate that 1) the upward growth of vertical fracture is expected for normal faulting and strike slip stress regimes; 2) the fracture initiation at casing shoe section prevails for common stress range at deep formation; 3) an inclined open hole tends to decrease fracture pressure gradient for normal faulting and reverse faulting stress regimes and 4) an open hole with building up trajectory may shift fracture initiation location from casing shoe to well toe by a lower breakdown pressure. The proposed model predicts fracture initiation at well toe location for Jolokia-1 stimulation by NaBr brine.

From Fracture Gradient to Spectrum of Lost-circulation Pressures: A Paradigm Shift?

In a naturally-fractured formation, the maximum mudweight (the lost-circulation pressure gradient) allowed along the interval is distributed between the minimum and maximum in-situ stress gradients. For a vertical wellbore drilled in an extensional stress environment, the spectrum of lost-circulation pressure gradients is dominated by the values close to the maximum (vertical) in-situ stress gradient. For a vertical wellbore drilled in an compressional stress environment, the spectrum of lost-circulation pressure gradients is dominated by the values close to the minimum (vertical) in-situ stress gradient. The minimum required length of the open-hole testing section increases with the length of the interval to be drilled, but there is no clear dependence of the minimum required length on the fracture density.

Cryogenic-Fracturing Treatment of Synthetic-Rock With Liquid Nitrogen

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 185050, “Experimental Study and Modeling of Cryogenic-Fracturing Treatment of Synthetic-Rock Samples With Liquid Nitrogen Under Triaxial Stresses,” by B. Yao and L. Wang, Colorado School of Mines; T. Patterson, Devon Energy; T.J. Kneafsey, Lawrence Berkeley National Laboratory; and X. Yin and Y. Wu, Colorado School of Mines, prepared for the 2017 SPE Canada Unconventional Resources Conference, Calgary, 15–16 February. The paper has not been peer reviewed. Cryogenic fracturing is a waterless stimulation technology that uses cryogenic fluids to fracture unconventional oil and gas reservoirs, and, to date, the underlying mechanism has been investigated rarely and is often understood poorly. This study aims to investigate the efficacy and feasibility of cryogenic-fracturing technology in enhancing the permeability of unconventional-reservoir-rock analogs. Laboratory cryogenic-fracturing experiments and finite-difference modeling are integrated to reveal the process and mechanism of cryogenic fluids in creating fractures in synthetic-rock samples. Introduction Traditional hydraulic fracturing relies on mostly water-based fracturing fluids and usually consumes a tremendous amount of water. The usage of water not only can cause potential formation-damage issues but also can place a significant stress on local water resources and the environment. Thus, waterless stimulation technologies, especially cryogenic fracturing, are being developed to solve these issues. Cryogenic fracturing uses cryogenic fluids such as liquid nitrogen to fracture unconventional oil and gas reservoirs. Fractures will be induced by the dramatic change of temperature when a warm body, such as reservoir rock, is exposed to a frigid fluid, such as liquid nitrogen. Although the feasibility of cryogenic-fracturing technology has been demonstrated by both laboratory experiment and pilot field tests, the mechanism behind it was rarely investigated and is poorly understood. A preliminary test involved a series of experiments investigating patterns of surface fractures and the effect of cryogenic treatment after submerging concrete-rock samples into liquid nitrogen. Computed-tomography scans showed that the fracture penetrated into the center of the block after 30 minutes of submersion. Further cryogenic-fluid-injection tests on concrete and shale samples have demonstrated the efficacy of permeability enhancement around the wellbore by injecting liquid nitrogen at both low and high pressures. Experimental Approach To conduct a cryogenic-fracturing treatment in a manner similar to that seen in field applications, the authors created a testing environment with sample sizes (8×8×8 in.) between the core and the real-reservoir scales. Liquid nitrogen was circulated into cubic samples through 6-in.-deep boreholes drilled from the top of the samples and cased with stainless-steel tubing by epoxy for the top 2 in. The confining stresses were applied on each sample by a triaxial-loading system that has the capability of providing a true triaxial-stress condition with different stresses along three different axes. The liquid nitrogen was drawn from a tank, injected directly into the wellbore, and then vented through the annulus space to the environment. The purpose of liquid-nitrogen circulation is to achieve a better cooling effect on the openhole section of the wellbore. Pressure, temperature, and stress data were collected during the experiment.

Determination of transient temperature distribution inside a wellbore considering drill string assembly and casing program

Heat exchange efficiency between each region of the wellbore and formation systems is influenced by the high thermal conductivity of the drill string and casing, which further affects temperature distribution of the wellbore. Based on the energy conservation principle, the Modified Raymond, Simplified and Full-scale models were developed, which were solved by the fully implicit finite difference method. The results indicated that wellbore and formation temperatures were significantly influenced at the connection points between the drill collar and drill pipe, as well as the casing shoe. Apart from the near surface, little change was observed in temperature distribution in the cement section. In the open-hole section, the temperature rapidly decreased in the circulation stage and gradually increased in the shut-in stage. Most important, the simulated result from the full-scale model coincided with the measured field data better than the other numerical models. These findings not only confirm the effect of the drill string assembly and casing programs on the wellbore and formation temperature distribution, but also contribute to resource exploration, drilling safety and reduced drilling costs.

Analysis of the Thermal and Hydraulic Stimulation Program at Raft River, Idaho

The Raft River geothermal field, located in southern Idaho, roughly 100 miles northwest of Salt Lake City, is the site of a Department of Energy Enhanced Geothermal System project designed to develop new techniques for enhancing the permeability of geothermal wells. RRG-9 ST1, the target stimulation well, was drilled to a measured depth of 5962 ft. and cased to 5551 ft. The open-hole section of the well penetrates Precambrian quartzite and quartz monzonite. The well encountered a temperature of 282 °F at its base. Thermal and hydraulic stimulation was initiated in June 2013. Several injection strategies have been employed. These strategies have included the continuous injection of water at temperatures ranging from 53 to 115 °F at wellhead pressures of approximately 275 psi and three short-term hydraulic stimulations at pressures up to approximately 1150 psi. Flow rates, wellhead and line pressures and fluid temperatures are measured continuously. These data are being utilized to assess the effectiveness of the stimulation program. As of August 2014, nearly 90 million gallons have been injected. A modified Hall plot has been used to characterize the relationships between the bottom-hole flowing pressure and the cumulative injection fluid volume. The data indicate that the skin factor is decreased, and/or the permeability around the wellbore has increased since the stimulation program was initiated. The injectivity index also indicates a positive improvement with values ranging from 0.15 gal/min psi in July 2013 to 1.73 gal/min psi in February 2015. Absolute flow rates have increased from approximately 20 to 475 gpm by February 2 2015. Geologic, downhole temperature and seismic data suggest the injected fluid enters a fracture zone at 5650 ft and then travels upward to a permeable horizon at the contact between the Precambrian rocks and the overlying Tertiary sedimentary and volcanic deposits. The reservoir simulation program FALCON developed at the Idaho National Laboratory is being used to simulate and visualize the effects of the injection. The simulation model uses a discrete fracture network generated for RRG-9 using acoustic borehole imaging and analysis of microseismic activity. By adjusting the permeability of the fractures, a pressure history match for the first part of the stimulation program was obtained. The results of this model indicate that hydraulic fracturing is the dominant mechanism for permeability improvement for this part of the stimulation program.

Factory-like Optimum Drilling Design of Cluster Well in Jimsar Well Block

The deep heavy oil reservoir of Jimsar well block, which located in Xinjiang oilfield, was developed by cluster well in 2016. In view of the ground environment, long open hole section and poor wellbore stability, the scheme which based on the research of factory-like wellsite platform deployment, well trajectory design and reservoir protection, was designed and carried out in the block. Firstly, the platform was divided into different control regions according to the anti-collision requirement. Secondly, truck-mounted drilling rig and civil power were applied to the factory-like drilling. Thirdly, well track was designed to be three parts: straight, increase and steady. The design can improve the proportion of composite drilling footage. Fourthly, the method of plane scanning and normal surface scanning was adopted to ensure the safety of downhole trajectory. Finally, the natural polymer drilling fluid system and drilling fluid reuse system were used to protect environment and reduce drilling cost. The results show that the maximum reducing time of single drill rig is 32.5 day, and the penetration rate of whole platform is increasing continuously.

First Hydraulic Stimulation in Fractured Geothermal Reservoir in Pohang PX-2 Well

The first hydraulic stimulation for enhanced geothermal system (EGS) development in Korea had been conducted in the PX-2 well of 4,348 m depth in Pohang EGS site from January 29th to February 20th, 2016. Treatment histories of injection rate, wellhead pressure and corresponding induced microseismicity data were obtained from the stimulation test upon 140 m long open hole section at the well bottom. Wellhead pressure was up to 89MPa and considerable level of flow rate was attempted up to 47 L/sec. Microseismicity observation showed a trend of lager and more frequent seismicity occurrence in shut-in phase than in injection phase. The injectivity index during the stimulation periods had increased as 2.7 times in January 30th at the wellhead pressure of 73MPa. Postulating the existence of a major fracture zone intersecting the open hole section, the transmissivity and the corresponding equivalent aperture of the fracture were evaluated. Required breakdown pressures by hydrofracturing and hydroshearing mechanisms were estimated based on the various scenarios on the in-situ stress condition, major fracture zone orientation and shear failure criteria.

Application of dynamic simulation to assess the effectiveness of well clean-up in a horizontal gas well

Well clean-up operation involves the removal of drilling and completion fluids from the wellbore before diverting the well to production facilities. Natural flow clean-up is preferred due to its relatively low cost and simplicity. Depending on the weight of the initial contents in the wellbore and the reservoir properties, artificial lift assisted clean-up such as nitrogen injection through coiled tubing may be required for some wells to ensure the well clean-up objectives are achieved. Well clean-up is transient in nature thus necessitating the need for a dynamic simulation approach to assess the effectiveness of different clean-up options and arrive at the optimal procedure before embarking on the actual field operation. In the current study, a comprehensive-multiphase-transient-simulator (OLGA) was used to predict the clean-up of a gas well with relatively short horizontal open-hole section and low reservoir pressure. Dynamic simulations of clean-up operations for different scenarios such as mud cake lift-off pressures and uncertainties in well productivity were conducted to assess the effectiveness of natural clean-up. Well clean-up failure could lead to impaired deliverability and potential for preferential flow hotspots. The study also assessed if coiled tubing-assisted operations would be beneficial in cases of natural clean-up being ineffective. This paper demonstrates the importance of using transient simulations to provide useful insights into flow and pressure dynamics inside the wellbore during clean-up which can help engineers to predict, design and optimise well clean-up operations, thus increasing the probability of a successful clean-up operation.

An Integrated Approach to Solving Sustained Casing Pressure in the Cana-Woodford Shale

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 174525, “Bridging the Gap: An Integrated Approach to Solving Sustained Casing Pressure in the Cana-Woodford Shale,” by G. Landry, R.D. Welty, SPE, M. Thomas, M.L. Vaughan, and D. Tatum, Schlumberger, prepared for the 2015 SPE Well Integrity Symposium, Galveston, Texas, USA, 2–3 June. The paper has not been peer reviewed. Many wells in the Cana-Woodford shale suffer from chronic sustained casing pressure (SCP) because of poor cement-sheath bonding. Using simulation software, centralization of the production casing was evaluated, and an optimized frictional pressure hierarchy was then designed. The engineered placement method ensured complete cement coverage around the casing through an optimized frictional pressure hierarchy. This multilayered approach using mechanically optimized slurries with different mechanisms of action, including self-healing, provided a comprehensive cementing portfolio that contained layers of contingency. Introduction One of the major operators in the Cana- Woodford field experienced poor bond logs and SCP both before and after stimulation, with the greatest number of issues appearing after stimulation. SCP can be defined as the presence of pressure in the annulus of nonstructural strings. The presence of SCP is an indication of a path of flow of hydrocarbons to the surface. SCP is typically caused by poorly placed cement or by not taking into account all factors in a well, such as stimulation conditions. The cement is placed in the annulus for many reasons, but one of the more significant is to provide zonal isolation. The zonal isolation is needed for stage-to- stage isolation in fracturing; isolation of the fracture treatment from shallower formations, which are typically in a lower-stress environment; and for prevention of hydrocarbon flow to surface. This paper presents the methodology and specific considerations that were taken into account to integrate all known information and causal learnings from logging to design a system to provide zonal isolation in the challenging Cana- Woodford shale. Field and Design Evaluation Borehole Geometry. Drilling practices can have a significant effect on cement-placement results. Several factors must be examined when evaluating a wellbore (e.g., washouts, hole size, dogleg severity, azimuthal gradients, curve build rates). All these factors can affect the ability to remove cuttings properly, to place centralizers effectively, and to remove mud efficiently. The operator placed emphasis on controlling these factors to help improve the likelihood of success. An oil-based mud (OBM) was used throughout the openhole section to maintain wellbore stability in the shale formation. Centralizer Program. The use of centralizers in horizontal wells is not a common practice because of a perception that they might impede the ability of casing to reach the bottom. With improvements in casing hardware technology and modeling software, effective centralization can be achieved in horizontal wells. Without proper casing centralization, the casing will lie on the low side of the hole. This contact with the wellbore will make mud removal impossible, and placement of cement around the pipe will not be achieved. This can also have an effect on a stimulation treatment.

Initiation and propagation of fracture shearing during hydraulic stimulation in enhanced geothermal system

This paper develops a generic model to estimate the location of shearing onset, the required pressure, and the overall shearing growth direction during the hydraulic stimulation in Enhanced Geothermal System, for which massive volume of fluid is injected into the fractured rockmass through a long open hole section. General studies on the effects of the stress condition on the shearing initiation and propagation captured some basic features related to the observed induced seismicity. Upward growth of shearing prevails for most stress conditions and a dense fluid favors downward shearing. Performed case studies demonstrate the developed method is potentially applicable to provide first order assessment of shearing initiation and propagation during hydraulic stimulation in a fractured EGS reservoir.

Microseismic reflection imaging and its application to the Basel geothermal reservoir

We have developed a new approach for reflection seismic imaging using microseismic waveform data. We took the specific character of microseismic downhole data into account and were able to image regions in the direct vicinity or inside of a seismically active zone. We used a directional migration method that reduced imaging artifacts caused by the low aperture of the data, but required estimation of the wavefield polarization. We also used hodogram analysis to identify parts of data that provided reliable polarization estimates. Only these parts were then used for imaging, whereas the rest of the data are excluded. The approach was successfully applied to microseismic waveforms recorded during and after the stimulation of the enhanced geothermal system in Basel, Switzerland. This data set included more than 2000 events recorded at five sparsely distributed borehole sensors. The reflection images revealed a distinct network of reflectors in the vicinity of the open hole section within the injection well. The results were compared with the injection borehole ultrasonic image revealing a quite good agreement. Combined analysis of imaged reflectors, event locations, and event focal mechanisms indicated that the approach resolved mostly aseismic highly permeable fluid pathways, whereas most of the seismicity occurred in the second-order fractures.

Crack Features and Shear-Wave Splitting Associated with Fracture Extension during Hydraulic Stimulation of the Geothermal Reservoir in Soultz-sous-Forêts

The recent tomography results obtained within the scope of the Enhanced Geothermal System (EGS) European Soultz project led us to revisit the meso-fracturing properties of Soultz test site. In this paper, we develop a novel approach coupling effective medium modeling and shear-wave splitting to characterize the evolution of crack properties throughout the hydraulic stimulation process. The stimulation experiment performed in 2000 consisted of 3 successive injection steps spanning over 6 days. An accurate 4-D tomographic image was first carried out based upon the travel-times measured for the induced seismicity [Calo M., Dorbath C., Cornet F.H., Cuenot N. (2011) Large-scale aseismic motion identified through 4-D P-wave tomography, Geophys. J. Int. 186 , 1295-1314]. The current study shows how to take advantage of the resulting compressional wave (Calo et al., 2011) and shear-wave velocity models. These are given as input data to an anisotropic effective medium model and converted into crack properties. In short, the effective medium model aims to estimate the impact of cracks on velocities. It refers to a crack-free matrix and 2 families of penny-shaped cracks with orientations in agreement with the main observed geological features: North-South strike and dip of 65°East and 65°West [Genter A., Traineau H. (1996) Analysis of macroscopic fractures in granite in the HDR geothermal well EPS-1, Soultz-sous-Forets, France, J. Vol. Geoth. Res. 72 , 121-141], respectively. The resulting output data are the spatial distributions of crack features (lengths and apertures) within the 3-D geological formation. We point out that a flow rate increase results in a crack shortening in the area imaged by both compressional and shear waves, especially in the upper part of the reservoir. Conversely, the crack length, estimated during continuous injection rate phases, is higher than during the increasing injection rate phases. A possible explanation for this is that cracks remain large because the system has time to relax. We also calculate the extension and opening rates during all hydraulic stimulation sets. While the opening rate is unchanged, the extension rate varies depending on the stimulation phase. It is also shown to be higher around and above the open-hole section than below. This can indicate a potential upward path that makes fluid percolation easier within the granite formation, this path being induced by the temperature gradient. We also compare the evolution of crack extension during injection with shear-wave splitting. Split shear waves were recorded at 2 stations during hydraulic stimulation and processed in terms of splitting parameters. The fast shear-wave polarization remains constant and parallel to the maximum horizontal stress orientation while the amplitude of splitting varies with time. We observe a good agreement between travel-time differences and crack extension rates during the first 4 days of the stimulation experiment. Afterwards, these two parameters depart from each other. This study emphasizes the added value of the coupling between effective medium modeling and shear-wave splitting to monitor meso-scale cracks in reservoirs submitted to hydraulic stimulation.

Development and evaluation of an electropositive wellbore stabilizer with flexible adaptability for drilling strongly hydratable shales

In order to overcome serious instability problems in hydratable shale formations, a novel electropositive wellbore stabilizer (EPWS) was prepared by a new approach. It has good colloidal stability, particle size distribution, compatibility, sealing property, and flexible adaptability. A variety of methods including measurements of particle size, Zeta potential, colloidal stability, contact angle, shale stability index, shale dispersion, shale swelling, and plugging experiments were adopted to characterize the EPWS and evaluate its anti-sloughing capacity and flexible adaptability. Results show that the EPWS has advantages over the conventional wellbore stabilizer (ZX-3) in particle size distribution, colloidal stability, inhibition, compatibility, and flexible adaptability. The EPWS with an average particle size of 507 nm and an average Zeta potential of 54 mV could be stable for 147 days and be compatible with salt tolerant or positive charged additives, and it also exhibited preferable anti-sloughing performance to hydratable shales at 77, 100, and 120 °C, and better compatibility with sodium bentonite than ZX-3 and KCl. The EPWS can plug micro-fractures and pores by forming a tight external mud cake and an internal sealing belt to retard pressure transmission and prevent filtrate invasion, enhancing hydrophobicity of shale surfaces by adsorption to inhibit hydration. The EPWS with flexible adaptability to temperature for inhibition and sealing capacity is available for long open-hole sections during drilling.

Conceptual model and numerical analysis of the Desert Peak EGS project: Reservoir response to the shallow medium flow-rate hydraulic stimulation phase

A series of stimulation treatments were performed as part of the Engineered Geothermal System (EGS) experiment in the shallow open-hole section of Desert Peak well 27-15 (September 2010–November 2012). These injections at variable wellhead pressures, both below and above the magnitude of the least horizontal principal stress (Shmin), produced injectivity gains consistent with hydraulically induced mechanical shear and tensile failure in the surrounding rock. A conceptual framework for the overall Desert Peak EGS experiment is developed and tested based on a synthesis of available structural and geological data. These data include down-hole fracture attributes, in situ stress conditions, pressure interference tests, geochemical tracer studies, and observed induced seismicity. Induced seismicity plays a key role in identifying the geometry of large-scale geological structures that could potentially serve as preferential flow paths during some of the stimulation phases. The numerical code FLAC3D is implemented to simulate the reservoir response to hydraulic stimulation and to investigate in situ conditions conducive to both tensile and shear failure. Results from the numerical analysis show that conditions for shear failure could have occurred along fractures associated with a large northeast-trending normal fault structure located ∼400m below the injection interval which coincides with the locations of most of the observed micro-seismicity. This structure may also provide a hydrologic connection between EGS well 27-15 and injection/production wells further to the south–southwest.

The impact of cleats on hydraulic fracture initiation and propagation in coal seams

Cleats are systematic, natural fractures in coal seams. They account for most of the permeability and much of the porosity of coalbed methane reservoirs and can have a significant effect on the success of hydraulic fracturing stimulation. Laboratory hydraulic fracturing experiments were conducted on coal blocks under true tri-axial stress to simulate fracturing stimulation of coal seams. Fractures were initiated by injecting a water gel with luminous yellow fluorescent dye into an open hole section of a wellbore. The impact of cleats on initiation and propagation of hydraulic fractures in coal seams is discussed. Three types of hydraulic fracture initiation and propagation pattern were observed in this study: 1) The hydraulic fracture initiated and then grew along the cleat. 2) The hydraulic fracture initiated along a butt cleat or a fracture (natural or induced by drilling) oriented roughly in the minimum horizontal stress direction, then turned to propagate along the first face cleat that it encountered or gradually turned towards the maximum horizontal stress direction. 3) The hydraulic fracture initiated perpendicular to the minimum stress and, when it encountered a face cleat, tended to propagate along the cleats if the extension direction does not deviate greatly (<20° as determined in this paper) from the maximum horizontal stress direction. When a coal seam is hydraulically fractured, the resulting fracture network is controlled by the combined effect of several factors: cleats determine the initiation and extension path of the fracture, the in-situ stress state dominates the main direction of the fracture zone and bedding planes impede fracture height growth.

FeS-Scale Cleanout With High-Pressure Coiled Tubing and Tailored Fluid

This article, written by Dennis Denney, contains highlights of paper SPE 169759, ’Extreme Challenges in FeS-Scale-Cleanout Operation Overcome Using Temporary Isolation, High-Pressure Coiled Tubing, and Tailored Fluid Systems,’ by Mustafa Buali, Noel Ginest, SPE, Jairo Leal, and Oscar Sambo, Saudi Aramco, and Alejandro Chacon and Jose Vielma, Halliburton—Boots &amp; Coots, prepared for the 2014 SPE International Oilfield Scale Conference and Exhibition, Aberdeen, 14-15 May. The paper has not been peer reviewed. The gas-producing carbonate zones of the Ghawar field in eastern Saudi Arabia have been affected by extensive iron sulfide (FeS) scale deposition, reducing overall gas production and increasing risks during well interventions. Previous remediation attempts used workover rigs, which can be costly because of the time necessary for workovers and lost production. Hydrogen sulfide (H2S) levels (2 to 5%) in the reservoir also contribute to higher costs and risks with the use of workover rigs. H2S in the reservoir poses a safety concern with the returns at surface and a concern with potential corrosion of the coiled tubing (CT) and completion. Therefore, the safest and most economical method was deemed to be mechanical descaling with CT. Introduction Two wells were descaled mechanically by use of CT. Each well involved four major challenges: low reservoir pressure, higher reservoir temperature, horizontal openhole completion, and highspecific- gravity (3.7 to 4.3) scale. The low reservoir pressure required payzone isolation to enable circulating out the heavy scale and to minimize fluid losses to the formation. With a bottomhole temperature as high as 310°F, the operational envelope of temporary chemical packers in combination with lost-circulation materials (LCMs) to isolate the openhole section had to be expanded. Following mechanical descaling with CT, the final challenge was cleaning out the LCM in the horizontal open hole and bringing the well back to maximum gas production by use of pinpoint stimulation techniques. Scale Composition Many scale samples have been collected and characterized throughout the years with X-ray diffraction (XRD), X-ray fluorescence, scanning electron micrographs, and microscopic methods (thin section). Although the exact chemical composition of the scale changes from well to well and varies with depth in a given well, the scale deposits are mixtures of many compounds, usually dominated by FeS minerals including pyrrhotite, troilite, mackinawite, greigite, pyrite, and marcasite.

Angola Ultradeepwater Completion Designs Deliver Prolific Production

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 166257, ’Angola Ultradeepwater Development: Pinnacle Completion Designs Deliver Prolific Production,’ by J.F. Pena, A.Q. Joseph, N. Oakey, B. McNerlin, SPE, and S.A. Ralph, BP, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed. BP’s largest subsea development, PSVM, is the first ultradeepwater development in Africa and is the most expansive subsea development in the industry to date because of its water depth and geographical spread. It sits in 2000-m-deep water northwest of Luanda, Angola. This paper discusses the keys to the successful delivery and well productivity of the first seven of 40 planned wells of the development. Introduction The PSVM development is an ultradeepwater project offshore Angola (Fig. 1). The development will access resources from four fields—Plutao, Saturno, Venus, and Marte—which will be tied back to a single central floating production, storage, and offloading (FPSO) vessel. All 40 of the planned development wells are subsea, in water depths ranging from 1800 to 2050 m. Of the 40 wells planned, 22 are producers and 18 are injectors. All four fields produce from and inject into poorly consolidated Miocene turbidite sandstone reservoirs; consequently, downhole sand control is required for all development wells. Sandface-Completion Design The principal design objectives of the sandface completions for the development wells were Access all net sand across multiple units separated by long shale intervals in trajectories from 0 to 90° and openhole lengths from 100 to 600 m. Keep the formation sand in situ for producer wells, and design openhole water-injection wells highly tolerant of fines backproduction to the wellbore. Provide assurance of installing robust sand control, and limit solids production to target levels. Minimize equivalent circulating density for a low-fracture-gradient environment. Minimize formation damage and shale reactivity, thus providing maximum productivity and injectivity by achieving mechanical skin factors of less than +5 for producer wells and less than +7 for injector wells. Provide facility to incorporate downhole flow control or shale isolation through high-integrity openhole zonal isolation. Use equipment with a proven track record where possible, and verify equipment reliability and integrity for first-time correct operation and 20-year well life. Minimize losses to the formation while running the upper completion, and enable the completion to be landed, tested, and packer set without slickline or coiled-tubing intervention. Producer-Sandface-Completion Basis of Design. The completion type assessed to be capable of meeting the design objectives for production wells was an openhole gravel pack (OHGP). Taking into consideration the properties of the rocks exposed in the long openhole sections and the operating environment, a viscous-gel-type gravel pack with alternative path functionality was selected over a circulating alpha/beta-type gravel pack, to provide increased assurance of installation success.