Fluid diversion in heterogeneous carbonate formations is critical to the design of successful stimulation treatments. In cased andperforated wells, microstructural damage around the perforated tunnels represents a significant challenge for the analysis of flow distribution along the wellbore. While this damaged or"crushed" zone has been a subject of numerous studies involving sandstones, the specific mechanisms of perforation damage in carbonates and theeffect on flow efficiency are not well understood. We examine the carbonate crushed zone at a fundamental level by interpreting the results of flow experiments on perforated cores using direct observation and analysis of the crushed zone at the porescale.
Injectivity index was recorded in Indiana limestone (IL) cores perforated using a gas-filled wellbore, an approach that suppresses wellbore dynamics and produces worst-case damage conditions. After the flow test, continuum modelsof the perforated coreswere constructed fromcomputerized tomography (CT) scans and used to calculate core flow efficiency (CFE) andaverage crushed zone permeability. Novel image analysis algorithms extracted the radial variation of pore-scale quantities across the crushed zone from high-resolution scans of thin sections at multiple axial locations along the tunnel. A correlation wasthen developed which estimates the radial variation of permeability in the near-tunnel region from each thin section. The permeability model is calibrated using analytical solutions that connect the crushed zone and virgin rock permeability profiles to experimental measurements made in the core test. The calibration approach makes use of a new approximate analytical solution for the flow field around a perforation with nonuniform tunnel geometry and crushed zone damage.
In the flow experiments, we observe a persistent drop in CFE for multiple charge types and test fluids as the initial core permeability is increased over two orders of magnitude. This is found to coincide with a decreasing ratio of average crushed-zone to virgin-rock permeability. Thin section analysis reveals that crushed zone damage is dominated by pore compaction near the tunnel edge, which has a characteristic signature in terms of the radial variation of porosity and pore-perimeter to surface-area ratio. Analysis of the spatial distribution of permeability suggests that flow efficiency is controlled by a low-porosity zone near the tunnel edge in which the damage is dominated by porecompaction.
Ridner, Dmitry (Texas A&M University) | Frick, Taylor (Texas A&M University) | Zhu, Ding (Texas A&M University) | Hill, A. Daniel (Texas A&M University) | Angeles, Renzo (ExxonMobil Upstream Research Company) | Vishnumolakala, Narendra (ExxonMobil Upstream Research Company) | Shuchart, Chris (ExxonMobil Development Company)
Acid jetting occurs as a result of pumping acid through limited entry liner completions, causing high velocity streams to impinge against the wellbore wall. The dissolution effect of jetting differs significantly from conventional matrix acidizing. Acid jetting causes cavities to be formed at the points of contact of the jet with the rock, with wormholes forming beyond the cavity. Jetting has been shown to be an effective technique for placing acid along extended reach laterals, removing filter cake, and enhancing wormhole propagation.
The velocity of the impinging jet and its standoff distance from the rock causes some of the acid to penetrate the formation and some to flow back in the annular space of the liner. Two types of dissolution mechanisms occur: surface dissolution forming the cavity, and matrix dissolution forming the wormholes. These dissolution mechanisms are highly dependent on acid injection rate, velocity of the jet, temperature, and permeability of the formation. The differences between the matrix dissolution mechanism of acid jetting and that of conventional matrix acidizing are most obvious at low acid injection rates.
Experiments were performed with the intention of quantifying the difference in pore volume to breakthrough between acid jetting and matrix acidizing, as well as determining the effect of increased temperature, rock permeability and acid concentration on this value with respect to acid injection rate. Baseline parameters of room temperature, 15% HCl and 2-4 mD Indiana limestone were individually compared with experiments run at 180°F, 28% HCl, and Indiana limestone cores of 30, 60 mD, and 140 mD. The effect of jetting velocity was also investigated by changing the diameter of the orifice from which the stream exits. Direct comparison with conventional matrix acidizing was made by eliminating the jetting effect of the stream through mechanical dispersion.
Acid jetting creates a point of heightened interstitial velocity at the contact of the acid and the rock, causing wormhole propagation to happen at a faster rate than it would in conventional matrix acidizing at that injection rate. This effect is especially pronounced as jetting velocity is raised above that of matrix acidizing, and tapers off at progressively higher jetting velocities.
Cores can be considered the ground truth only if we eliminate or minimize their damage during the core cutting, tripping, and surface handling. Such damage would adversely alter their properties. An important source of core damage is during tripping when the quick decompression may cause damage due to the induced microfractures. In this paper, a state-of-the-art geomechanical model is introduced and applied for determining the safe tripping rates.
The Thermo-Poro-Elastic (T-P-E) geomechanical approach used in this study includes the mathematical derivation of the diffusion time required for the imposed pore pressure difference to dissipate while also considering the effects due to the temperature changes, the mud cake, and swabbing. The work utilizes different approaches for fluid modeling in a transient manner during tripping for the water-bearing, gas- bearing, and oil-bearing cores.
In this work, the hydraulic diffusivity and the fluid type have been introduced as the main factors controlling the maximum allowable safe tripping rates. A relationship between the allowable decompression rate and the hydraulic diffusivity will be presented for each specified fluid type. In addition, the results indicate that water-bearing cores can be safely tripped as quickly as the normal tripping speed of the wireline, even with core permeabilities of as low as 0.01 mD. For gas and oil-bearing cores, the safe tripping rates are determined to be much less than the water-bearing cores as the fluids expand with pressure drop along its journey to the surface. The results show that the tripping rate is the lowest for the oil-bearing cores particularly in the vicinity of the bubble point and gas critical pressure (as the gas expansion pushes the oil and applies significant viscous forces across the core pore throats).
This paper is a novel work developing T-P-E and mathematical models for the case of core tripping considering the effects of the pore pressure change, temperature change, the mud cake, and swabbing. The hydraulic diffusivity and the fluid type have been considered as the controlling factors. The approach has been applied for modeling the tripping of water, gas, and oil-bearing cores to provide maximum allowable tripping rates.
There are many causes for injection wells to perform poorly; in this paper, we address the effect of residual hydrocarbons near the wellbore, which reduce the rock's effective permeability to brine, thus decreasing well injectivity. Immobile hydrocarbon saturations are found around injection wells when these are drilled above the water-oil contact level, which arises when a producer well is switched to injection, or the formation's underlying aquifer is hard to reach. Furthermore, oil can accumulate around a wellbore when produced brine containing even trace amounts of hydrocarbons is used as the injection fluid. To address this problem, it is possible to flush out hydrocarbons around the wellbore by periodically injecting small amounts of surfactants for short periods. This technique leverages the capillary desaturation behavior of a multi-phase fluid mixture, wherein increasing the capillary number of a rock-fluids system beyond a threshold value will decrease the residual hydrocarbon saturation. The capillary number, which characterizes the ratio of viscous to capillary forces, can be increased by injecting surfactant loaded brine; this reduces the hydrocarbon-brine interfacial tension which reduces the capillary forces, decreases the system's residual hydrocarbon saturation, and increases the brine's effective permeability. To efficiently assess the impact of a surfactant flush, we perform digital rock multi-phase flow simulations on Berea and Fontainebleau sandstones at different capillary numbers. The simulations provide the residual hydrocarbon saturation and the brine's effective permeability as a function of capillary number, which is related to the amount and type of surfactant. These results are then used in a radial wellbore simulation to compute the attainable injection rate for a maximum allowable pressure drop. Since the largest pressure drop occurs very close to the wellbore, the surfactant flush is very effective even though it only affects a few feet from the wellbore. For the specified scenario we observe a potential well performance improvement ranging between 20% and 150%. By using digital methods, this study was performed in about two weeks, at lower cost than Special Core Analysis Laboratory (SCAL) physical testing, and with ideal reproducibilty since the capillary number can be modified without affecting the sample or any other aspect of the test procedure.
Vaidya, Nirupama (Schlumberger) | Lafitte, Valerie (Schlumberger) | Makarychev-Mikhailov, Sergey (Schlumberger) | Panga, Mohan Kanaka Raju (Schlumberger) | Nwafor, Chidi (Schlumberger) | Gadiyar, Balkrishna (Schlumberger)
Viscoelastic Surfactant (VES) fluids have been used in many openhole gravel packing applications with the shunt tube technique as they offer several advantages over polymeric fluids. However, existing VES fluids have temperature limitations. The objective of this work was to develop a new viscoelastic surfactant (VES) based fluid for gravel packing wells with temperature up to 325°F while retaining the advantages of existing VES fluids.
The new fluid system consists of a surfactant, a cosurfactant, and a nanoadditive. The performance of the new fluid system was evaluated in laboratory experiments up to 325°F. The properties studied and discussed in this paper are shear recovery time, rheology (viscosity versus shear rates), gravel suspension, and core retained permeabilities. The optimization of the final fluid formulation based on sensitivity of the target properties to concentration of each component is also detailed in the paper.
The new VES-based gravel pack carrier fluid incorporating a nanoadditive showed significantly improved performance at elevated temperatures compared with conventional fluids. In particular, while the conventional VES fluids do not meet the gravel suspension requirement, the new fluid system is able to suspend the gravel under static conditions up to 325°F. In addition, the viscosity at low shear rates is improved while the viscosity at high shear rates is comparable to existing VES fluids. Tests with outcrop cores of varying permeabilities demonstrated the fluid's minimal formation damage. The complete VES fluid system with nanoadditive was found to be compatible with both monovalent and divalent brines at densities up to 14.0 lbm/gal. As such, it is a more cost-effective alternative to xanthan-based carrier fluids, which are incompatible with inexpensive calcium brines and thus necessitate sodium bromide or formate brines depending on the density requirements. Based on the extensive laboratory study, it can be concluded that the new fluid system outperforms conventional VES gravel pack carrier fluids at high temperatures while retaining the benefits of the conventional VES fluids.
The new fluid system significantly extends the temperature limit of VES-based gravel packing carrier fluids. The fluid system can also be used with many completion brines and mixed at a wide density range, making it an excellent alternative to conventional polymeric fluids used in gravel packing applications.
Satti, Rajani (Baker Hughes, a GE company) | White, Ryan (Baker Hughes, a GE company) | Ochsner, Darren (Baker Hughes, a GE company) | Sampson, Tim (Baker Hughes, a GE company) | Zuklic, Stephen (Baker Hughes, a GE company) | Geerts, Shaun (Owen Oil Tools)
As the industry looks forward to increasing operational efficiencies and maximizing productivity, there has been increasing interest in perforating systems that can combine perforating and well stimulation in a single operation. For this reason, propellants have a unique place in the perforating community as a stimulation/enhancement tool that can significantly improve productivity and lower operator costs. However, in complex well completions (high angle, doglegs or long horizontal wells), friction ignition and other concerns with traditional propellant methods have led to the advent of a new enhanced perforating system, whereby the energetic materials are deployed within the gun body, requiring specific charge performance, and in specially designed carriers.
The enhanced perforating system has been successfully deployed in the field. In the interest of conducting a quantitative evaluation, this study is focused on developing and demonstrating a fit-for-purpose flow laboratory apparatus to evaluate the benefits of the enhanced perforating system using standard API-RP 19B Section-IV procedures. The experimental apparatus was designed to closely represent the actual gun system, whereby the detonation of the perforating charge initiates a complex, sequentially burning reaction of the energetic material that generates a high-pressure gas pulse. A comprehensive testing program in Berea sandstone using shaped charges in conjunction with these energetic propellant materials at representative downhole conditions was conducted.
The analysis from the experimental tests was not limited to standard measurements, but also included advanced interpretation techniques involving high-speed transient pressure analysis, 3D computerized tomography and productivity analysis. Preliminary analysis of the test data showed promising trends with respect to increased peak pressure, improved clean-up and extended tip-region around the perforation tunnel. Furthermore, the HSE aspects of this enhanced system from a laboratory standpoint were also investigated.
In summary, the above study presents a laboratory study and quantitative evaluation of an enhanced perforating system that combines shaped charges and energetic materials. This system has been field proven to assist in pre-frac treatment. The benefits of the system can be further realized in conjunction with frac-optimized perforating systems, whereby frac-treatments are optimized to enhance productivity.
Bestaoui-Spurr, Naima (Baker Hughes a GE company) | Langlinais, Kevin (Baker Hughes a GE company) | Stanley, David (Baker Hughes a GE company) | Usie, Marty (Baker Hughes a GE company) | Li, Chunlou (Baker Hughes a GE company)
Recovery of frac-pack fluids is often poor in offshore operations. Large amounts of stimulation fluids left in the fracture may leak-off into the porous formation or block part of the proppant pack thus impairing hydrocarbon production. A typical frac-pack treatment fluid contains water-wetting surfactants to maximize flow-back fluids. However, the amounts recovered are still low and new methods are needed to improve well cleanup. Using a proppant that is neither oil nor water wet has the potential to solve some of these issues.
Proppant surfaces were permanently modified to a neutral wettability state. Molecules having both hydrophobic and oleophobic properties were covalently bonded to the oxide surfaces, leading to robust engineered interfaces with low surface energy thus potentially improving flow. To support this concept of neutral wettability proppant, laboratory studies were conducted to determine performance under flow and cleanup ability compared to native proppant surfaces. This neutral wettability proppant was also used in several completions in the Gulf of Mexico. Two case histories using the neutral wettability proppant are presented and compared with offset wells as well as performance laboratory data. Flowback data as well as production data are reported.
Laboratory results showed that the neutral wettability enhanced surfaces not only reduce water saturation but also improve oil movement. This demonstrates the ability of these materials to improve clean up and hydrocarbon flow within the proppant pack. When this proppant was applied in frac-pack completions it was observed that flow-back recovery was dramatically increased compared to offset wells that used similar proppant. Cleanup time was reduced allowing first oil to appear more rapidly. Furthermore, production data show that oil flow that the productivity index is higher when the surface of the proppant is neutral. These results demonstrate this material as next generation proppant for improving flow and cleanup in frac-pack completions.
Al-Jasmi, Ahmad Kh. (Kuwait Oil Company) | Alsabee, Ali (Kuwait Oil Company) | Al-Awad, Ahmad (Kuwait Oil Company) | Attia, Adel (Kuwait Oil Company) | Elsayed, Abdou (Kuwait Oil Company) | El-Mougy, Ahmed (Petrosas Oil Services and Radial Drilling Services)
Reservoir management requires continual efforts to identify opportunities for production enhancement. Radial Drilling (RD) technology is a method for production optimization by extending the contact area with reservoir. It utilizes hydraulic jetting energy to create several lateral holes within the zones of interest along different directions.
A candidate cased hole well-A was selected based on sub-normal production from a sandstone reservoir. Three extended laterals holes, at ±300 ft lengths each, are made using the RD technology. Job planning includes core studies, static and rotary jetting test using clean fluid. In order to avoid any possible formation damage during operations, RD job procedures have been optimized by using the different fluids mixtures during jetting, backwash and enlarging the created lateral holes. Jetting fluid used was brine mixed with NH4CL and Mutual Solvent, and followed by 10% HCL regular Acid.
The results showed a significant improvement in well productivity compared with previous well history. The post-treatment production test showed a ±110% gain in oil rate resulting from the improved reservoir deliverability. The dominant factor responsible for the success of this technology is the meticulous planning and testing before job execution. Moreover, it has proven to be an effective solution to bypass the deep damaged area around the sandface, and to improve the production recovery from heavy oil zones. The success of the new Radial Drilling technology with the optimized procedures can be implemented as a best practice in similar wells in north Kuwait fields.
This paper presents the advantages of the Radial Drilling technology in the recovery of bypassed crude oil from existing thin reservoirs, the optimized radial drilling procedures that ensured a clean lateral hole, and the evaluation of the impact compared to the conventional procedures.
Formation damage caused by mineral scale development is one of the major reasons resulting in reduction of hydrocarbon production during a well's life cycle. Scale inhibitors are most widely used to control scale deposition in producing wells either by adding them directly to fracturing fluids in wells where stimulation treatment is planned or by performing remedial squeeze treatments. Prolonged protection can be achieved by adding proppant-sized solid inhibitor during the stimulation treatment. The current study addresses the benefits of alternate methods of placing solid inhibitor depending on the well completion system. In the case where stimulation treatment is not planned, the solid inhibitor can be placed in the annular space between the production tubing and formation in the long open-hole horizontal well to provide extended protection as the well starts to produce. This solid inhibitor once depleted as evidenced by residual analysis can be recharged effectively by injecting liquid inhibitors that restores the effectiveness, allowing extension of protection life-times.
An appropriate inhibitor chemical was first identified for the treatment from the produced water scaling analysis. A suitable solid scale inhibitor was prepared by adsorbing this chemical onto a high surface area water/oil insoluble substrate, and multiple surface modifications made to control the inhibitor release rate. The long term inhibitor chemical release profile was evaluated by packing this solid inhibitor into a column and eluting with synthetic produced water at expected bottom-hole temperatures of 200°F.
The solid inhibitor elution tests show long protection times when solid inhibitor was applied. The projected inhibitor protection would be more than 60,000 pore volumes (PVs) of produced water before the inhibitor chemical was substantially depleted. In a well, 3000 pounds of this inhibitor can be potentially placed in the annular space, which would result in preventing scaling for 330 thousand barrels of water being produced, with protection life-time of more than 5 years (at 170 barrels of water per day). The presence of high surface area substrate allows inhibitor to be recharged after inhibitor depletion. The efficiency of the inhibitor recharge application was investigated by a series of column experiments.
Placing the solid inhibitor into the annular space will delay the requirement for scale squeeze treatments significantly, and reduce the overall well maintenance cost for the operator, particularly in an offshore environment. The ability of the solid inhibitor to be re-charged using conventional scale squeeze chemistry enables more chemicals to be retained when subsequent squeeze is potentially performed on the wells.
Jafarov, T. (King Fahd University of Petroleum & Minerals) | Mahmoud, M. (King Fahd University of Petroleum & Minerals) | Al-Majed, A. (King Fahd University of Petroleum & Minerals) | Elkatatny, S. (King Fahd University of Petroleum & Minerals) | Bageri, B. (King Fahd University of Petroleum & Minerals)
The main objectives of this work are to prevent water blockage problem of wells drilled to tight gas reservoirs by minimizing fluid invasion and to reduce solid invasion with the optimized sodium silicate concentration in actual drill-in fluid and ultimately, improving well productivity by obtaining high return permeability after forming the very thin, impermeable and easily removable filter cake.
Static filtration tests were conducted on 0.25″ tight cores at 300°F under 300 psi ΔP with 250 psi back pressure and 500 psi inlet pressure to collect filtrate volumes. Rheology tests were performed up to 140°F under atmospheric and at 300°F under 300 psi pressure. Rheology experiments were performed for base fluid and with 0.05, 0.075, 0.1 wt%, while filtrations were also performed for 0.5, 1 and 1.5 wt% sodium silicate concentrations. Initial and return permeabilities were measured by injecting 3 wt% KCl through 2″ core sample under constant flow rates after damaging it. CT numbers were obtained before and after damaging 2″ core by doing CT Scan.
Filtrate volume and cake thickness reduced by 53% and 65% with 0.075 wt% (3.5 ml & 0.7 mm), respectively, compared than base fluid (7.4 ml & 2 mm). 0.075 wt% determined as an optimum concentration. Water blockage problem of tight gas wells prevented by minimizing the fluid invasion. Measured initial and return permeabilities of 2″ core remained same as 1.3 mD. This result proved that no solid invasion occurs with 0.075 wt% sodium silicate and in case of 100% filter cake removal, return permeability will be 100%. Forming filter cake with 0.7 mm thickness lets us to claim that it can be completely removed by washing with 15 wt% HCl. Obtained CT numbers confirmed return permeability measurement as well.
Barite flotation recovery and solubility concentration of silica with PH are the two approaches that should be considered together to explain the mechanism of 0.075 wt% sodium silicate. Polymerization effect shows itself for ≤0.075 wt%, while amorphous silica effect occurs for >0.075 wt%. Polymerization effect became the evidence of obtaining 100% return permeability.