Hwang, Jongsoo (The University of Texas at Austin) | Sharma, Mukul (The University of Texas at Austin) | Amaning, Kwarteng (Tullow Ghana Limited) | Singh, Arvinder (Tullow Ghana Limited) | Sathyamoorthy, Sekhar (Tullow Ghana Limited)
Understanding injectivity is a critical element to ensure that sufficient volumes of water are being injected into the reservoir to maintain reservoir pressure, to ensure good reservoir sweep and minimize well remediation. It is, however, challenging to describe the large injectivity changes that are sometimes observed in injectors operating under fracturing conditions. This study presents a field case study with the following objectives: 1) explain the complicated injectivity changes caused by fracture opening/closure with injection-rate variations, 2) define a safe operating envelope (for injection pressure and rate) that ensures fracture containment and injection into the target zone, and 3) prescribe how the injection rate should be changed to achieve higher injectivities. Injector operating conditions are developed using results from a full 3-dimensional fracture growth simulation to ensure fracture containment in a multi-layered reservoir.
We present field injectivity observations, a comprehensive simulation workflow and its results to explain injector performance in a deep-water turbidite sand reservoir with multiple splay sands. Understanding the impact on fracture propagation and containment allows us to make quantitative suggestions for the operating envelopes for long-term injection-production management. Strategies for high-rate injection to sustain the injection well performance long-term are discussed.
Simulation results show that, at injection rates over 5,000 bwpd, injection induced fractures propagate. Fracture closure induced by injection shut-down is used to compute the bottom-hole pressure decline as a function of time. The fracture opening/closure events and the thermally induced stress were the primary factors impacting injectivity. The simulation results suggested several ways to improve the injectivity while ensuring fracture containment. Injection under fracturing conditions into a single zone at a high rate is shown to be feasible and this allows us to support a substantial increase in injectivity. This must, however, be done at pressures that will not cause a breach in the bounding shales. The 3-dimensional fracture simulations identified the operating pressure and rate envelope to maximize the injection rates while minimizing the risk of breaching the cap rock and inter-zone shales.
Nielsen, Julie (The Danish Hydrocarbon Research and Technology Centre, Technical University of Denmark) | Poulsen, Kristoffer G. (Department of Plant and Environmental Sciences, University of Copenhagen) | Christensen, Jan H. (Department of Plant and Environmental Sciences, University of Copenhagen) | Solling, Theis I. (Center for Integrative Petroleum Research, College of Petroleum Engineering & Geoscience, King Fahd University of Petroleum and Minerals)
Mature fields often times surprise with respect to the production from the various wells across reservoir sections. This is for example the case in a tight chalk field that we have used as a case study for newly developed technique that employs oil finger printing in the analysis of production data. A small subset of wells has been found to produce significantly better than the remainder and we set out to explore whether the root cause is that there is a connection to higher lying reservoir sections through natural or artificial fractures. This was done with advanced analytical chemistry (GC-MS) and a principal component analysis to map differences between key constituents of the oil from wells across the reservoir section. The comparative parameters are mainly derived from biomarker properties but we also developed a way to directly include production numbers. The approach provides means to correlate the molecular properties of the oil with the production and the general composition that determines density and adhesive (to the rock) properties. Thus, the results provide a new angle on the flow properties of the oil and on the charging history of the reservoir. It is clear from the analysis that the subset of wells does not produce better because of a connection to an upper reservoir section that contributes to the production with oil of a different composition because the molecular mix is indeed quite similar in each of the investigated wells. It is not possible to rule out that there is a connection to an upper-lying section with oil from the same source. One aspect that does differs across the field is the ratio of heavy versus light molecules within each group of molecules and the results show that the region that produce better has the lighter components. We take that to indicate that the lighter components come from oil that flows better and thus is produced more easily. The reservoir section with the lighter oil also lies higher on the structure and is therefore must likely to have been charged first so part of the favorable production seems to be a matter of "first in" "first out". A GC-MS approach such as the one proposed here is cost-effective, fast and highly promising for future predictions on where to perform infill campaigns because the results are indicative of charging history and flow properties of the oil.
In the majority of fractured oil and gas wells, conventional perforating is the typical approach of choice to provide the primary connectivity of fractures to the wellbore, and in horizontal wells the very discrete nature of this connection assumes a significantly higher importance. In multi-fractured horizontal wells, this connection drives the ability to efficiently place the fracture treatments during pumping and the efficiency with which the fracture can subsequently be produced. Consequently, selection of the most appropriate connection technique can be absolutely key to many aspects of a successful implementation of a fracturing campaign.
The use of shaped-charge perforating is quite commonplace and predominantly considered as best practice for the majority of scenarios, in order to establish fracture/wellbore connectivity. However, there are certain situations where such approaches may not provide an efficient solution. This is particularly true in those horizontal wells drilled and completed in complex stress regimes, also in reasonable permeability reservoirs, that have multiphase flow potential or with just a few transverse fractures that are expected to produce at moderate to high production rates from each frac. In these particular cases, a complex connection resulting from perforating can often be detrimental to fracture width creation, making proppant placement challenging and reducing effective fracture conductivity. Additionally, convergent and multi-phase flow behaviour can create extremely high pressure drops in the near wellbore area subsequently impeding the productivity.
While open-hole completions can be one of the methods to deal with this situation, by effectively eliminating the "problem" at source, this is typically delivered at the expense of loss of control on the point of fracture and also with a statistical isolation failure rate. When this is implemented in multistage/multi-cluster frac environments (effectively hundreds of fracs) such statistical failure is an acceptable risk. However, when a single-well frac count is just 3, 4 or 5 per well, any statistical failure can be materially impactful on the well productivity. In those cases when open-hole is not an attractive approach then cased-cemented is preferred, and the application of abrasive jetting can provide an effective alternative to the use of shaped-charges.
This paper will fully describe a suite of tests performed with different shaped-charges as well as abrasive jetting perforators, static holes and dynamic slotting for the multi-fractured horizontal wells in the Khazzan tight-gas condensate field in the Sultanate of Oman. The paper will also include a comprehensive review of multiple injection tests that were performed in both Khazzan vertical and horizontal wells (
Since the late 1980s when Maersk published their work on multiple fracturing of horizontal wells in the Dan field, the use of transverse multiple-fractured horizontal wells has become the completion of choice and the “industry standard” for unconventional and tight-oil and tight-gas reservoirs. Today, approximately 60% of all wells drilled in the United States are drilled horizontally, and nearly all are multiple-fractured. However, little work has been performed to address and understand the relationship between the principal stresses and the lateral direction. This paper has as its goal to fundamentally address the questions: In which direction should I drill my lateral? Do I drill it in the direction of the maximum horizontal stress (longitudinal), or do I drill it in the direction of the minimum horizontal stress (transverse)?
This work focuses on how the horizontal well’s lateral direction (longitudinal or transverse fracture orientation) influences productivity, reserves, and economics of horizontal wells. Optimization studies, with a single-phase fully 3D numerical simulator including convergent non-Darcy flow, were used to highlight the importance of lateral direction as a function of reservoir permeability. The simulations, conducted for both oil and gas formations over a wide range of reservoir permeability (50 nd–5 md), compare and contrast the performance of transversely multiple-fractured horizontal wells with longitudinally fractured horizontal wells in terms of rate, recovery, and economics. This work also includes a series of field case studies to illustrate actual field comparisons of longitudinal vs. transverse horizontal well performance in both oil and gas reservoirs, and to tie these field examples to the numerical-simulation study. Further, the effects of lateral length, fracture half-length, and fracture conductivity were investigated to see how these parameters affect the decision of lateral direction in both oil and gas reservoirs. In addition, this study seeks to address how completion style (openhole or cased-hole completion) affects the selection of lateral direction.
The results show the existence of a critical reservoir permeability, above which longitudinal fractured horizontal wells outperform transverse fractured horizontal wells. With openhole completions, the critical permeability is 0.04 md for gas reservoirs and 0.4 md for oil reservoirs. With cased-hole completions, longitudinal horizontal wells are preferred at a reservoir permeability above 1.5 md in gas reservoirs, and transverse horizontal wells are preferable over the entire permeability range of this study (50 nd–5 md) in oil reservoirs. These are new findings. Previous work generally suggested that longitudinal horizontal wells are a better option for gas reservoirs with permeability over 0.5 md, and for oil reservoirs with permeability over 10 md.
This work extends prior study to include unconventional reservoir permeabilities. It provides critical permeability values for both gas and oil reservoirs, which are validated by the good compliance between actual field-case history and simulation results. This work also demonstrates a larger impact of completion method over fracture design. These findings could guide field operations and serve as a reference for similar studies.
The objective of this study is to introduce a technique of far-field diversion using a mixture of soluble solid particles and an engineered proppant that can ensure that the temporarily bridged fractures re-open and remain propped for hydrocarbon flow after the soluble material has fully dissolved. Far-field diversion is required inside the fracture network to increase complexity by creating additional branch fractures through overcoming stresses holding the natural fractures closed. Usually, diverter particles temporarily bridge inside the fracture to create a low-permeability zone that increases the net pressure within the fracture and enables redirection of the next fluid stage to previously unstimulated intervals. However, if the diversion does not include proppant, the created fracture may close after particle dissolution.
Two tests were performed in this study: solid bridging test to describe the bridging capabilities of solid particulate diverters as a function of fracture width (0.04 to 0.08 in.); and conductivity reduction tests to determine the reduction in the flow rate due to the particle pack permeability. Two types of particle diverters (Diverter A and B) were tested. Diverter A is typically used for low- to medium-temperature applications (less than 225°F) and Diverter B for high-temperature applications (greater than 225°F). The two diverters have nearly the same particle size and distribution, the only difference being a difference in particle shape.
Modeling performed before the experimental work indicated that a proppant size of 50 mesh or higher minimized the far-field segregation between the proppant and 20 mesh soluble particles under all modeled conditions. Modeling also showed that reducing the proppant size to a larger mesh number improved proppant placement in the far-field area with good vertical coverage. Based on this information, the diverter particles for the tests were selected to be in the medium-size range (10 to 50 mesh) while the proppant particles were selected to be in the fine size range (70 to 140 mesh). At a low injection rate, slickwater fluid (2 cP) may not have adequate transport characteristics to place soluble diverter particles for far-field application. Modeling indicated that a carrier fluid with viscosity of 10 cP could carry the soluble diverter at least 130 ft from the wellbore.
Experimental data, using the CFD recommended sizes of proppant-diverter mixture, confirmed that a loading of 0.5 ppga of Diverter A was needed to bridge and plug the 0.04-in. slot width, while only 0.25 ppga of Diverter B was needed to plug the same width. The spherical shape of Diverter B helps to bridge inside that fracture more than the flake shape of Diverter A. Finally, both diverters significantly reduced the conductivity of the test slot discs.
He, Youwei (China University of Petroleum, Beijing) | Cheng, Shiqing (China University of Petroleum, Beijing) | Li, Lei (China University of Petroleum, Beijing) | Mu, Guoquan (Research Institute of Petroleum Exploration and Development, Changqing Oilfield) | Zhang, Tiantian (The University of Texas at Austin) | Xu, Hainan (China University of Petroleum, Beijing) | Qin, Jiazheng (China University of Petroleum, Beijing) | Yu, Haiyang (China University of Petroleum Beijing)
Because of the effect of reservoir heterogeneity and fractures in low-permeability reservoirs, effective characterization of waterflood direction and front has become a challenging issue under high-water-cut condition. To achieve better understanding of such a complex problem, a work flow, containing statistical and numerical techniques, is developed to characterize waterflood direction and front distribution in Changqing oilfield by using both flow rates and bottomhole-pressure (BHP) data. The work flow includes four steps: First, dynamic analysis is used to qualitatively investigate the relationships between injector and producers; then, the constraint multiple-linear-regressions (MLR) method is applied to calculate the interwell-connectivity coefficients, which was used to quantitatively describe the waterflood direction by production and injection rates. On the basis of the results of the two former steps, we can adopt numerical well testing as our third step to deal with flow rates and BHP data to characterize the waterflood direction and front. Finally, the streamline method is used to simulate the waterflood front and high-permeability channel distribution on the basis of the outcome of the three preceding techniques. Compared with individual methods, the proposed work flow can offer more perspectives and ways to make a comprehensive and deep investigation of the waterflood reservoir. The results obtained by this work flow enable proactive and better waterflood management in the Well Group W16 in Changqing oil field; namely, the water cut of producers decreases, meanwhile the oil production increases by nearly 40% referring to the field data in 2015. With the help of the information obtained by this work flow, operators could make more-reasonable decisions on waterflood management such as well-pattern optimization and injection–production parameters adjustment.
The drilling, completion, and stimulation of multiple fractured horizontal wells has proven to be an effective means of extracting hydrocarbons from unconventional resources. Since the first application of this technology by Maersk in the Dan Field in the mid-1980's oil and gas reservoirs have seen improved productivity and profitability. However, identifying the key drivers for success of multiple fractured horizontal well technology has proven difficult especially in unconventional reservoirs where data is limited. With few vertical wells, logs and core data typically used for building a basis of completion and stimulation design are often lacking. As a result, other methods of identifying success drivers must be developed and utilized.
To this end, this paper utilizes a data-mining and statistical analysis of well, completion, fracture stimulation, and production data to establish the important parameters for success in horizontal wells in the Montney Formation of Alberta and British Columbia, Canada. In this study more than 3,300 horizontal wells were characterized with respect to lateral length, completion type, number of stages, fracture fluids pumped, proppant loading, costs, and production. The study utilized the statistical software JMP to identify key relationships between well data. The software system allowed standard screening and more advanced graphical methods to be applied to validate the dataset. From the quality assured dataset various additional parameters were calculated and used in the analysis.
Both regression analysis and statistical ‘heat maps’ were used to correlate and visualize data trends. Heat maps are shown as a useful tool for visualizing strongly trending data. Another finding from this study is that cased and cemented horizontal wells in the Montney Formation had significantly better initial productivity (+31%) and first year cumulatives (+42%) than open hole external packer completion systems even though the cased and cemented wellbores had fewer stages (-40%), larger stimulations (+390%), and increased costs (+14%).
While additional completed stages may increase cumulative recovery in the Montney Formation, statistical analysis demonstrates the recovery per stage decreases after a certain stage density. This conclusion is consistent with recent findings (
This work is important as it identifies relevant completion trends in the Montney Formation and completion and stimulation practices linked to higher recovery and well success. This is also the first field-wide statistical review of wells completed in the Montney Formation using more advanced data mining and statistical analysis. The work lays a foundation for application of these techniques to more unconventional and tight oil and gas reservoirs.
Clemens, Torsten (OMV) | Finkbeiner, Thomas (OMV) | Chiotoroiu, Maria-Magdalena (OMV) | Pettengell, Katherine (OMV New Zealand) | Hercus, Samuel (OMV New Zealand) | Suri, Ajay (University of Petroleum & Energy Studies) | Sharma, Mukul M. (University of Texas)
Field X is located off-shore beneath ~100m of water. Initially, long horizontal production wells and sub-vertical water injection wells were used for the field development. When one of the oil production wells located at the edge of the field watered out, it was decided to convert it for water injection. Since reservoir permeability is low (tens of mD), generation of injection induced hydraulic fractures is expected.
The following questions needed to be addressed in order to mitigate risks and guarantee operational success of the water injection program:
How will injectivity of the long horizontal injector develop over time? How long would injection induced fractures grow over time? In which direction are the fractures going to grow with respect to the horizontal wellbore (i.e., could they reach an adjacent producer)? What will be the outflow fraction of the injected water from the horizontal wellbore versus the induced fracture?
How will injectivity of the long horizontal injector develop over time?
How long would injection induced fractures grow over time?
In which direction are the fractures going to grow with respect to the horizontal wellbore (i.e., could they reach an adjacent producer)?
What will be the outflow fraction of the injected water from the horizontal wellbore versus the induced fracture?
To answer these questions, a simplified horizontal well flow model was coupled with a fracture model. This fracture model required geomechanical input in form of present day in-situ stresses (both orientation as well as magnitudes) and pore pressures as well as rock mechanical properties in form of Young's moduli and Poisson's ratio. Resulting from the geomechanical analysis, we found that the present day stress state is that of a normal to strike slip faulting environment (i.e., Sv ~ SHmax > Shmin) whereby well head pressures in excess of 80 bar with Shmin gradient of 0.6 psi/ft would induce fracturing in the reservoir with a well confined direction.
The geomechanical-fluid flow model calculated the various pressure drops from the wellbore sand face into the reservoir, location of the different fronts (thermal, water), and propagation of the induced fracture along with plugging of the inside fracture faces.
A good history match of the ongoing water injection into the horizontal well was achieved. The forward simulations showed that fractures are being generated dependent on the injection rates, water quality, injection temperature and the minimum principal horizontal stress (Shmin). When injection rates are too high, a substantial amount of water – in excess of 50% – is expected to be injected into the induced fracture despite very good water quality and the horizontals appreciable length (i.e., more than 2000 m).
The geomechanical model suggests that induced fractures are more likely to initiate in a region of lower stress along the wellbore caused by localized facies variation and propagate from there initially in a direction closely parallel to the wellbore (i.e., (sub-) longitudinal with the wellbore axis by ±20°).
To optimize field management and to avoid the generation of extensive induced transverse fractures, water injection is recommended at a maximum injection rate of 7,500 bbl/d, a minimum injection temperature above 55°C, and a water quality of less than 3ppmv (6 micron particle diameter). The optimization is confirmed with the observation that the closest producer shows signs of pressure support with an increase in oil production, but no evidence of premature water breakthrough.
Chakravarty, Krishna Hara (Center for Energy Resources Engineering, Department of Chemical and Biochemical Engineering, Technical University of Denmark) | Fosbøl, Philip Loldrup (Center for Energy Resources Engineering, Department of Chemical and Biochemical Engineering, Technical University of Denmark) | Thomsen, Kaj (Center for Energy Resources Engineering, Department of Chemical and Biochemical Engineering, Technical University of Denmark)
Migration of fines, and formation of oil emulsion have been independently observed during smart water flooding both have been suggested to play a vital role in enhanced oil recovery (EOR). But, the exact role of fines and the reason of emulsion formation are not well studied for carbonate reservoirs. This study shows that addition of water and crude oil on calcite fines leads to formation of soluble oil emulsions in the water phase. Formation of these emulsions and its implication in EOR has been experimentally analyzed.
To characterize the formation of theses emulsions study has been conducted for various water insoluble salts were used as fines (including, Li2CO3, MgCO3, CaCO3, CaSO4, SrSO4, BaSO4 and reservoir CaCO3 fines). Different types of oil and water was added to these fines. To study conditions of oil emulsion formation, design oil was used consisting of hexane and hexadecane. Heptylamine and hexadecylamine were doped in various compositions to mimic the base number of the oil. Experiments were conducted for pure crude oil and doped oil to understand its implications in EOR. Composition of initial and final floating oil was obtained through gas chromatographic (GC) analysis. The two were thereafter compared to obtain the composition of micelles formed.
The experiments showed how oil emulsions were formed when polar hydrocarbons are present in the oil. Mixtures of alkanes did not produce emulsions. In oil containing hexadecylamine 95% of the initial hexadecylamine was accumulated in the emulsions and only 5% was found in the floating oil. In oil samples containing heptylamine only 45-50% of its initial amount was accumulated in the emulsions. This indicates heavier amines can form more stable emulsions. Oil emulsions were produced with all the fines used, but the composition of these emulsions were dependent on the salt anions. In all carbonates, lighter amines preferred emulsions formation with lighter alkane. No such selectivity was observed in any of the sulfates. Results obtained with crude, doped and designed oil were consistent for both pure salts and outcrops. These results show that fines of carbonate released during fracturing, or sulfates formed during smart water flooding can form mixed wet water soluble oil emulsions which help to mobilize trapped oil, and increase the sweep efficiency.
The results clearly show oils with the same base number can have significantly different amount of emulsion formation with fines, and provides a detailed mechanism of further characterization of the oil. The study highlights the significance of fines during smart water flooding in carbonate reservoirs and shows how its role in EOR can be mistakenly underestimated.