Solvent injection, which is the only alternative to thermal methods to reduce the viscosity of heavy-oil, requires an effective solvent distribution in the reservoir to achieve the maximum oil-solvent contact. The dilution process, however, becomes slower as oil gets heavier. In this case, an initial interface exists between oil and -liquid or gas- solvent (similar to ultralow immiscible fluids cases). In case of heterogeneous reservoirs (fractured carbonates or wormholed oil sands), the diffusive mixing between the solvent in the fractures/wormholes and matrix oil requires longer contact times. Hence, an initial interface between the solvent and oil may exist and, depending on the wettability conditions, the existence of water and oil/solvent type, capillary imbibition (liquid solvent) or drainage (gas solvent) transfer into the matrix may take place. Intrusion of oil by capillary imbibition accelerates oil recovery reducing the time to get the oil and solvent contacted in order for the dilution (mixing) process to start.
To investigate this phenomenon and perform a parametric analysis, an experimental design was developed focusing on analyzing the oil-solvent mixing zone mechanisms. A wide range of oil types (50cp to 100,000cp) and solvents (heptane and decane) were used. Experiments were performed on oil saturated 3 × 7 cm 2-D glass (core scale) and glass capillary tubes by soaking them into solvent under static conditions. To identify the mixing process (by color gradient) and distinguish the phases, advanced illumination and photographic techniques were applied using UV light and coloring the solvent.
The followed experimental approach employed visual models at core and pore scale levels and successfully displayed the existence of both capillary imbibition and diffusion mechanisms in a solvent heavy-oil system. To what extent capillary imbibition could occur and assist in the recovery by miscible interaction was clarified for different oil, solvent, and wettability conditions. The results revealed that the solvent injection process might be enhanced by other mechanisms (imbibition or drainage) in heterogeneous reservoirs, which is usually neglected in modeling studies.
Initial capillary imbibition took place if the glass surface was more solvent-wet than the original oil. Diffusive mixing followed by convective mixing occurred. Time periods corresponding to different recovery mechanisms were identified for different wettabilities and oil viscosities.
Extraction of unconventional resources is vital to meet future hydrocarbon demand. However, the effective extraction of these unconventional resources cannot be accomplished by the application of conventional technologies. This study summarizes different combination of different Enhanced Oil Recovery (EOR) methods to recover effectively the low API gravity and high viscosity crudes to find the main factors affecting the EOR performances most. Several steam flooding, steam assisted gravity drainage, and solvent aided-steam processes (SA-SP) (both with asphaltene solvent and non-solvents) were tested on heavy, extra-heavy, and bitumen resources. Carbon dioxide, propane, n-hexane, and toluene were tested as solvents. While carbon dioxide, propane, and n-hexane are asphaltene non-solvents, toluene is asphaltene solvent. The process performances were discussed in terms of cumulative oil recovery and produced oil quality. Produced oil qualities were compared according to their asphaltene, clay, and water contents. Asphaltene content directly correlates to the water and clay contents of the produced oil samples. As the asphaltene content of produced oil increases while the water content increases, the clay content decreases. The worst produced oil quality was obtained by SAGD and toluene-SAGD. The experiments conducted with the asphaltenes insoluble solvents (carbon dioxide, propane, and n-hexane) produced the highest quality oil with low water content and high deasphalted oil content.
Chaudhry, Amjad (Eni Petroleum Co. Inc.) | Sallee, Adam (Schlumberger) | Burton, John (Schlumberger) | Lazzari, Andrea (Eni Petroleum Co. Inc.) | Kuck, Marc (Eni Petroleum Co. Inc.) | Ravagli, Bruno (Eni Petroleum Co. Inc.) | Simeone, Davide (Eni Petroleum Co. Inc.) | Kuwairi, Aousama (Schlumberger)
Nikaitchuq is the largest single-stakeholder development on the North Slope of Alaska. It is a multiyear, very shallow extended-reach drilling (ERD) project with more than 50 wells drilled from two sites, one of which is an artificial gravel island, targeting Schrader Bluff sands. A number of key drilling advances were implemented to reach the milestone of one million feet drilled as the scope of the development plan expanded to include new producer wells targeting a shallower sand, new in-fill multilateral producer branches, and a new extension plan targeting pay that is much more distant than the original development plan envisioned.
The minimum slot distance of 8 ft and the increasing density of wells drilled drove the development of a systematic anticollision management plan. Significant economic value was conserved by explicitly forming shut-in/turn-on criteria for offset wells, managing surface conductor drift, controlling drilling parameters exiting the surface conductor through the kickoff, implementing a new surveying technique, and identifying and accounting for directional "deadzones."
Abrasion wear occurs in the intermediate hole section bottomhole assembly (BHA) caused by high-angle well path geometry, often surpassing 85° inclination in tangent, combined with the presence of frequent hard stringers. The impact of wear has increased as the extended reach drilling ratio and directional difficulty index have increased year-on-year from 6.34 to 6.69, respectively. Well path geometry has progressed to limit the measured depth drilled through intervals where hard stringers are expected and to account for reduced directional performance at the later part of the hole section. The reduction of downhole tool repair costs and the elimination of downhole tool failures, ultimately leading to single-run, shoe-to-shoe drilling of a section 13,500-ft measured depth (MD) long—a record for Alaska—are the results of the focus on improving BHA design to limit wear.
Multiple reentry laterals have been geonavigated in close proximity with the parent wellbore among offset producer grassroots wells. A point-the-bit rotary steerable system has been introduced to drill ahead and deviate from the bottom of the milling rathole, below the whipstock and window, eliminating a motor run and saving substantial rig time on each lateral. A sourceless density logging-while-drilling (LWD) tool was introduced to manage drilling risk through zones of depletion.
These technical advancements demonstrate consistent improvement of the drilling learning curve over the course of 5 years drilling at Nikaitchuq. This will be the first literature that details the long-term drilling advances achieved in the project and a valuable technical reference for very shallow ERD wells where abrasion wear is a concern.
Dong, Xiaohu (China University of Petroleum-Beijing and University of Calgary) | Liu, Huiqing (China University of Petroleum-Beijing) | Hou, Jirui (China University of Petroleum-Beijing) | Liu, Guohua (Great Wall Drilling company, CNPC) | Chen, Zhangxin (University of Calgary)
Polymer flooding process is one of the most commonly-used EOR techniques for the waterflooded light-oil reservoirs. The further development after polymer flooding process is currently challenging the EOR techniques. Using the methods of physical simulation and numerical simulation, the feasibility of polymer-enhanced foam (PEF) injection process in post polymer-flooding reservoir is performed in this paper. Through the introduction of a concept of average foam-composite-index (FCI), an experimentally based screening criteria for PEF is proposed. And, the influence of polymer concentration on the plugging-effect of PEF is also experimentally investigated. After that, the parallel experiments of PEF injection and conventional foam injection are conducted. Then, based on the geostatistics data of an actual oil reservoir, a Lorentz-Monte-Carlo (LMC) algorithm is proposed to establish the heterogeneous geological models with different interlayer and plane permeability-variation-coefficients. Thus, the sensitivity of reservoir heterogeneity on the recovery performance of PEF injection is numerically analyzed, and the implementation plan of PEF injection is also optimized through an orthogonal test.
Experimental results indicate the plugging effect of PEF is significantly superior to the conventional foam. The optimal polymer concentration is 1500mg/L, and the injection of PEF could effectively enhance the oil recovery by about 17.1%. The improving effect of enhanced foam on oil recovery in heterogeneous reservoir is much more significant than that in the homogeneous reservoir. As the reservoir heterogeneity increases, the ultimate recovery factor increases. For the rhythm reservoir, the reverse rhythm reservoir with weak plane-heterogeneity and week interlayer heterogeneity could yield a better recovery performance. The optimal implementation plan of PEF injection process are that the slug size is 0.06PV, injection rate is 50t/d, gas/liquid ratio is 1:1, foamer solution is 0.5wt%, and polymer solution is 0.6wt%. This investigation sheds some important insights for the enhanced oil recovery (EOR) process of post polymer-flooding reservoir. It could be used as a tool for the successful design of PEF injection process during the high water-cut stage of post polymer-flooding reservoir.
Horizontal wells in liquids-rich shale plays are now being drilled such that lateral and vertical distances between adjacent wells are significantly reduced. In multistacked reservoirs, fracture height and orientation from geomechanical effects coupled with natural fractures create additional complications; therefore, predicting well performance using numerical simulation becomes challenging. This paper describes numerical simulation results from a three-well pad in a stacked liquids-rich reservoir (containing gas condensates) to understand the interaction between wells and production behavior.
This paper discusses the use of an unstructured grid-based numerical simulator that incorporates complicated geometries of both hydraulic and natural fractures. It can handle compositional simulation to better model gas condensates with special focus on timing of third well placement and the loss of conductivity effects on production from these wells. A base case was created with a stacked shale play containing three parallel wells but with staggered elevations. Variables used in this study include matrix permeability, condensate-to-gas ratio (CGR), fracture length, well staggering, time of well placement, conductivity degradation, and presence of natural fractures. Simulation runs were conducted for a five-year duration.
More than 20 compositional simulation runs were conducted. For the base case, staggering resulted in a slight decrease in both cumulative oil and gas production compared to a case without staggering. Matrix permeability had the most dominant effect on both oil and gas production. Fracture and matrix conductivity losses were more detrimental to cumulative gas production than oil production. For the limited cases studied, placement of the third well one year after the first two wells began producing resulted in a spike in both oil and gas production from the pad. This produced cumulative oil and gas amount was close to that of three wells producing simultaneously, especially if fracture half-lengths for the third well were the same as the first two. However, cumulative oil and gas production reduced significantly if fracture half-lengths were smaller than the other two wells. When all wells experienced significant conductivity loss, gas production was affected more than oil production when the third well was placed one year after the first two wells began producing. In all cases, placing the third well between the other wells was helpful in increasing overall production from this pad. Natural fractures increased both oil and gas production in the cases studied.
This paper addresses important issues associated with a liquids-rich unconventional play. It demonstrates successful use of unstructured grid-based reservoir simulation modeling to address well placement timing, well staggering, conductivity damage effects, natural fractures, hydraulic fractures not perpendicular to the wellbores, and several other important issues for which little is known so far. Results from this study type can be used to make important decisions regarding well placement and timing in a multiwell setting.
Prakoso, Andreas (Texas A&M University) | Punase, Abhishek (Texas A&M University) | Klock, Kristina (Texas A&M University) | Rogel, Estrella (Chevron Energy and Technology Center) | Ovalles, Cesar (Chevron Energy and Technology Center) | Hascakir, Berna (Texas A&M University)
Significant effort has been dedicated to understand the variables affecting asphaltene precipitation. Based on years of research, it is well known how variables such as temperature and pressure can affect the deposition of asphaltenes. However, much less is understood about the effect that asphaltene characteristics have on the tendency towards precipitation of different crude oils. We characterize extensively a series of n-pentane extracted asphaltenes and construct novel correlations with the stability of their corresponding crude oils.
11 different bitumen and crude oil samples are characterized first with API gravity and viscosity measurements, and thermogravimetric and differential scanning calorimetric analyses (TGA/DSC). The weight percentage of the asphaltenes in bulk samples are determined through n-pentane precipitation. The molecular structure of the asphaltenes is investigated with Fourier Transform InfraRed (FTIR) spectroscopy. Asphaltene stability is measured by ?PS and by determining the Asphaltene Solubility Profile. The impact of hydrogen deficiency, heteroatom content and solubility distributions on other properties such as viscosity and aggregation behavior is also explored.
It has been observed that there is weak relationship between the asphaltene content and API gravity or viscosity of the bulk samples. The weight percent of the light, intermediate, heavy, solid, and ash fractions of the asphaltenes, defined with TGA/DSC experiments, indicate that the carbon rich solid component of the bulk samples that can decompose over 550 °C, correlate with the weight percent of the asphaltenes in bulk oil. The ash content of the bulk oil, which is mainly composed of heavy metals like sulfur, nickel, and vanadium, is correlated to the amount of asphaltenes precipitated out of the oil. Moreover, FTIR and solubility profile analyses reveals that the polarity of the asphaltene molecules is affected not only by its molecular composition and structure but also by its interactions with other crude oil components.
This study discusses the impact of the physical and chemical properties of crude oils and their asphaltenes on asphaltene precipitation. Several asphaltene deposition mechanisms are developed and validated for 11 different crude oil and bitumen samples with different asphaltene contents, thereby providing important and fundamental insight into asphaltene related problems.
Decline curve analysis (DCA) is the most common method to forecast future production and to estimate ultimate recovery and reserves/well. The traditional form of DCA proposed by Arps is however restricted to boundary-dominated flow regimes. In unconventional shale plays, it is however likely that the transient flow regime may occur for the first few months or years of production. Consequently, the applicability of the traditional forms of DCA to early-time production data may not be appropriate.
This work is divided in to two main sections. In the first section, we apply some of the more recent decline curve models proposed for shale wells to production data acquired from the Woodford shale in Oklahoma. A comparison is then made between the different decline curve models in terms of their ability to replicate production history in a forecast mode. In the second section, we extend earlier work performed by other authors to compare well performance across different shale plays and over different time periods. The DCA presented in the earlier work utilizes a simple Arps decline; in this work, we utilize a composite decline curve that works for the linear transient flow regime and subsequent boundary dominated flows. Our work indicates that while the Arps decline curve analysis approach may be erroneous, in comparison to a more rigorous DCA, the errors are less than 20% in predicting EUR.
The concept of relative viscosity is widely used in literature for describing the rheological behavior of Newtonian and non-Newtonian fluids containing particles. Generally, nanoparticles are used at low concentrations; but Einstein equation hardly predicts the suspension viscosity values. Similarly, equations developed for high particle concentrations hardly made the predictions too. This paper presents the inability of Einstein and Krieger-Dougherty equations in predicting the relative viscosity of surfactant-based fluids (SBF), polymeric fluids, and SBF-polymeric fluid blends.
Concentrations of 5% and 33 lb/Mgal guar were used for the laboratory preparation of SBF and polymeric fluids respectively, and both fluids contained 4% potassium chloride (KCl). Also, the mixture of SBF and polymeric fluids in the ratios of 3:1 (vol.) and 1:3 (vol.) resulted into Blend-A and Blend-B fluids respectively. The addition of 20 nm silica nanoparticles, at concentrations of 0.058, 0.24, and 0.4% wt., to the clean fluids generated the nano-fluids. Rheological data were gathered with Bohlin CS-50 rheometer within a temperature range of 75 to 175 °F.
Silica nanoparticle concentrations of 0.058, 0.24, and 0.4% wt. were converted to 0.0083, 0.034, and 0.055 solid volume fractions respectively. Relative viscosity values could not be predicted using Einstein and Krieger-Dougherty equations. The nano-fluids display both increase and decrease in suspension viscosity; furthermore, their suspension viscosities were dependent on the solids volume fraction, temperature, and shear rate (9 to 1026 sec-1.). Lastly, relative viscosity correlations (that covered the whole range of values for which the experiments were conducted), previously developed by the authors, were included for complementary purpose. The correlations predict the viscosity of nano-suspensions as a function of solid volume fraction, temperature, and shear rate.
This work provides an insight into the behavior of suspension at nano-scale level. The prediction of viscosity of nano-suspensions depends on more than one parameter. Moreover, this study will facilitate the field application of these novel hydraulic fracturing fluids.
Short radius laterals, where a drilling tool is able to make a right turn in a cased wellbore and then penetrate some distance out into a formation, is an attractive technology for enhanced oil recovery for both existing and new field developments. Lateral holes with different geometries can penetrate untapped compartments, thin or by-passed pay, less permeable oil zones that cannot be sufficiently drained by conventional processes, and extend the effective radius of a well while reducing skin effects. A commonly referenced technology is radial jet drilling, where a specialized shoe is deployed in the well, a casing cutter cuts a hole through the pipe, and then a nozzle with high-pressure cutting jets is deployed on a hose at the end of coiled tubing. The technology has yet to become common in the United States, despite tens of thousands of candidate wells that could benefit from such a restimulation. Problems with jet drilling systems include: uncertainty in distance and direction of emplaced laterals; low available power to front-facing cutting jets, as most of the power has to be directed to rear-facing jets to keep the nozzle on the formation; and difficulties cutting hard formations and when encountering hard clasts.
The objective of this study was to evaluate a newly developed technology for production enhancement from low-permeability reserves that utilizes a purely mechanical drilling string deployed on coiled tubing that is able to make a right-angle turn in a wellbore and drill a ~1.5 in. diameter lateral 30 ft or more into a reservoir. To study the technology, two wells were selected and stimulated.
A simulation study for one of the field test sites, Millman field, a Grayburg/San Andres field in the Permian Basin, New Mexico, allowed a sensitivity study for optimization of lateral emplacements, optimal number of laterals per level, and allowed prediction of the impact of the recompletions. The prediction of lateral efficiency showed that the four emplaced laterals gave the best overall efficiency for enhancing oil production with 28.5% predicted incremental production in previously stimulated zones, and a 33.3% increase for previously unstimulated zones. Diagnostic techniques for monitoring lateral direction and placement based on small, chip-based gyroscope and accelerometer chips were developed and field-tested, verifying lateral emplacement during the field tests. The first test well saw ~40% increase in oil rate with emplacement of 12 laterals in three intervals. The second test well saw a 47% increase in production after 15 laterals targeted a previously untapped zone.
This paper presents, discusses, and validates the drilling technology, the simulation models and results, the sensor development, and field-testing of those three technologies at two wells, with the emplacement of 27 total laterals with lengths of up to 32 ft.
Viscoelastic surfactants (VES) have been used to replace polymer-based fluids as effective, cleaner, and non-damaging viscofying carriers in frac-packing, acid fracturing, and matrix acidizing. However, several limitations challenge the use of VES-based fluids including: thermal instability, incompatibility with alcohol-based corrosion inhibitor, and intolerance to the presence of contaminating iron. This work introduces a new VES-based acid system for diversion in matrix acidizing that exhibits excellent thermal stability and diversion performance in both low-and high-temperature conditions.
Rheology measurements were conducted on spent VES-acid system as a function of temperature (77- 300°F) at a pH of 4-5. The effect of acidizing additives on the VES viscosity was investigated. The additives included a corrosion inhibitor, non-emulsifier, iron-chelating agent, and iron-reducing agent. Single and dual coreflood experiments were performed using limestone core samples with an initial permeability range of 4-200 md and a permeability contrast of 1.5-55. Post CT-scan imaging was conducted to investigate the wormhole topography. The diversion characteristic of the new VES in the dual coreflood experiments was evaluated by the structure and the extent of wormhole propagation in the low-permeability core.
Rheological data for 15 wt% HCl spent VES-solutions showed a maximum viscosity of 200-800 over a temperature range of 150-170°F, depending on the VES concentration in the sample. Without acidizing additives, a minimum of 50 cP was obtained at 195, 230, 250, and 275°F at 4, 5, 6, and 8 vol% of the VES in solution, respectively. None of the tested acidizing additives had a negative impact on the VES viscosity. At 8% VES loading, the acidizing package was optimized such that a minimum of 75 cP was obtained at 300°F.
Dual coreflood experiments were conducted at 150 and 250°F, and the results proved the ability of the proposed VES to divert efficiently in limestone formations. Single coreflood experiments also confirmed these results. Coreflood data indicated that a range of permeability contrast of 4-10 is the optimum for diversion ability in terms of the final permeability enhancement of the low-permeability cores. The results revealed 18.6, 45.6, 82%, and infinity when the permeability contrast was 28.3, 14.4, 6. 3, 1.63, respectively. A dual coreflood experiment was conducted for two cores with a permeability contrast of 1.6 at 150°F. The VES-acid system in the presence of all acidizing additives exhibited divergent performance that exceeded the performance of the VES in the absence of additivies. These results prove the stable performance of the VES and the enhancement in viscosity response after addition of both the iron-control agent and the non-emulsfier, which resulted in less acid leakoff and better wormhole structure.