Unconventional shale drilling has developed rapidly during the last decade. The development of substantial prospects, especially in shale gas plays, requires advanced technologies and prudent well monitoring. Many new operational challenges are associated because of simultaneous operations, such as drilling and fracturing nearby wells.
While drilling, the interaction of the fractures from nearby wells results in pressure communication and unexpected well kicks. Because of the low porosity of those tight reservoirs, those uncommon well kicks have so far not been severe, but taking the time to control wellbore pressures adversely affects the efficiency of the drilling process and increases the non-productive time. Additionally, as fracturing becomes more efficient, and conductivity increases, possible future events might have much more dramatic consequences. This paper presents a method that uses the positional uncertainty of the well being drilled, positional uncertainty of the fractured/fracturing wells, and uncertainty of the fracture length and fracture orientation to avoid this problem. The paper discusses the reasons and challenges, techniques, and lessons learned to solve the simultaneous moving boundary conditions between the reference wells and multiple offset wells. The method of explicit solution avoids a trial-and-error procedure and provides excellent maneuverability of planning requirements. The modified model and methods provided the use of exact mathematical solutions and uncertainty ellipses estimates.
This method can also be used to monitor the influence of other variables, such as temperature cycling, oil drainage distance, wellbore storage effect, and reservoir pressure transients. The method presented can be used in the planning stage to ensure optimal well placement; it can also be used for designing super fractures between wells. The study indicates that the use of real-time data from drilling and fracturing wells can predict the need for remedial action.
A new family of anionic surfactants that has great potential for EOR applications was synthesized and characterized in our lab. The unique and versatile structure of these surfactants has endowed them with properties that are attractive for enhanced oil recovery. A detailed experimental study was carried out and is presented here on the oil-water and solid-water interfacial properties of seven novel molecules.
The interfacial properties of this series of seven anionic surfactants with different length of hydrophobic tail and linking spacer group show systematic trends in interfacial tension and static adsorption density with changes in solution conditions. These molecules showed excellent aqueous stability even in high salinity and hard brines. Ultra-low IFT values were measured at low surfactant concentrations. The synthesized Gemini surfactants also showed lower maximum adsorption densities than the conventional single chain surfactants. The results from this study showed the potential of utilizing these surfactants at low concentrations and in harsh reservoir conditions.
The Indian offshore field under study has "LA?? reservoir as one of the main producer. While the testing was carried out, nearly 20 wells were completed out of which 17 were on production, producing about 18,000 BOPD. "LA?? reservoir is relatively clean and well developed in the crestal part of the reservoir. The average thickness of "LA?? reservoir in the crestal part is 35-40m and increases upto 70m towards the flank. The Gas Oil Contact and Oil Water Contact are at 940m and 740m from MSL respectively. The IOIP and IGIP are of the order of 100.6 MMt and 2297 MMm3. In order to ascertain productivity of horizontal well, maximise oil recovery, prevent possible gas and water coning besides mastering of the technology, it was proposed to drill two horizontal wells.
This paper studies the Pressure Transient data of the Horizontal, Inclined and Vertical well of the same field. The interpretation of the horizontal well testing data was more complex due to development of shorter flow regimes. The data, however, is carefully analysed using the available software to determine several parameters including the average permeability and "k.h?? product. The diagnostic derivative plots are used to determine the different flow regimes. Using the results, the permeability anisotropy and specific productivity was calculated for each well system. Replacement Ratio of horizontal to vertical/inclined well was determined using Newton's mid-pt numerical method and the cost analysis was done. Replacement Ratio and Cost ratio was combined for comparison of the three well systems.
Replacement Ratio was determined to be 2.25 which means 2.25 vertical wells may replace 1 horizontal well with same rate of production while Cost ratio for horizontal to vertical well was 2.40. On combining the two, it implied that horizontal well system was marginally more suitable in addition to other benefits for the given field with given conditions which in other words signifies that the horizontal well system's efficiency wasn't upto the desired level and needs severe improvement.
Key Words- GOC, OWC, Horizontal well, Replacement Ratio, Cost Factor, Specific productivity.
Al-anzi, Ealian H.D. (Kuwait Oil Company) | Rao, Narhari Srinivasa (Kuwait Oil Company) | Al-Ashwak, Samar (Kuwait Oil Company) | Kidambi, Vijay Kumar (Kuwait Oil Company) | Al-ajmi, Neema Hussain (Kuwait Oil Company) | Rao, Jonna Dayakar (Kuwait Oil Company) | Al-ateeqi, Khalid Abdullatif (Kuwait Oil Company) | Al-Mayyas, Rawan (KOC) | Olderman, Allan Stefanic (Kuwait Oil Company) | Acharya, Mihira Narayan (Kuwait Oil Company) | Chakravorty, Sandeep (Schlumberger) | De Keyser, Thomas Lee
Deep, tight carbonate reservoirs of Pliensbachian, Sinemurian, and Hettangian Stages of the mid-Mesozoic Era are becoming very important in the continued pursuit of hydrocarbon prospects in North Kuwait. At present, a total of 21 wells have penetrated the targeted reservoir zones. Of these, 12 have been tested for hydrocarbon production covering a large area of about 1700 sq km. Further, six wells have produced oil and gas, with two deemed commercially successful.
The entire workflow to characterize these reservoirs is focused on delineating faults and associated fractures in individual wells. Detailed seismic study and volume curvature maps, revealed the existing fault and fracture corridors. Sub-seismic faults and subtle reverse faults with fractures were detected by log correlations and borehole image. Due to paucity of cores in these zones, descriptions of cuttings samples were used to identify faults and fracture zones, based on the presence of large euhedral crystals in the midst of cryptocrystalline dolomite, suggesting the percolation of hydrothermal fluids through fractures.
Many of the wells were drilled with an overbalanced mud system, leading to near-borehole porosity and permeability damage to the rock matrix and to the fracture system. Damage to natural fractures intersecting the well can prevent their detection, leading to missed potentially productive intervals. Mobility of hydrocarbons in these tight, fractured carbonate reservoirs depends upon (i) wells intersecting a natural fracture system that is sufficiently permeable and connected to a large volume of reservoir rock and (ii) the near-borehole area not having suffered irreversible damage due to overbalanced drilling. In summary, the proposed reservoirs are very tight carbonates (average 3 pu porosities) and a fracture play is considered to be the key factor in production. Acid stimulation produced multifold increases in productivity. Most of the wells were drilled overbalanced, which has negative impact on the producibility due to formation damage.
Increased energy demands for oil and gas have triggered the need to exploit high-pressure/high-temperature (HP/HT) fields, including extreme HP/HT and ultra HP/HT fields. However, well completion of ultra HP/HT fields is posing great technological challenges to operator and service companies. Existing completions technology seems to be reaching its design limits at around the 15,000 psi and 450°F territory.
As operators continue to drill into deeper and more extreme formations, the demand for technologies to suit these environments will steadily increase. Great efforts have been made to overcome the hurdles to develop safe and reliable completion tools qualified for conditions in excess of the 15,000 psi and 450°F territory across the industry over the years. A technological milestone was recently set in packer seal system development?the first 25,000-psi 500°F packer seal system.
Qualification testing was conducted with nitrogen to all the rating envelope points at 500°F with a cool down to 250°F.
The packer seal system passed all tests with no visible seal element extrusion, and no leaks were detected at any of the load points during testing.
This paper presents how this innovative seal system design evolved from several field-proven HP/HT seal systems, and how technological challenges are addressed by adopting state-of-the-art materials and design processes. The paper includes information about conceptual design, design optimization using finite element analysis (FEA), material characterization for both metallurgical and seal material, and seal assembly manufacturing. The qualification testing processes for this 25,000-psi 500°F packer seal system are also described, along with the market potential for these ultra-HP/HT wells.
It is a well known fact that the hydrocarbon demand increases by the day. Now, in order to meet this ever increasing demand it is essential for us to produce at the required rate over a specified period of time. The most prominent problem affecting production in gas wells is Liquid Loading. It is basically the inability of gas to remove liquids being produced in the wellbore. This occurs when the velocity of gas being produced falls down a particular value known as "critical velocity??. The produced liquid will accumulate in the well creating a static column of liquid, therefore creating a back pressure against formation pressure and reducing production until the well ceases production. This problem should be predicted early and dealt properly to prevent economic losses and produce efficiently.
Some notable correlations that exist for predicting the critical rate required for liquid unloading in gas wells include Turner et al., (1969), Coleman et al., (1991), Nosseir et al. (1997) and Li et al. (2001). However, these correlations offer divergent views on the critical rates needed for liquid unloading and for some correlations in particular, at low wellhead pressures below 500 psia. In this paper, we compared the critical velocity graphs obtained from different models for four different wells and concluded that Turner model gives the most conservative value of critical velocity of all the methods for any value of pressure. The turner model is most widely used and accepted in oil and gas industries and moreover all the theories are based on the Turners model.
Using Nodal Analysis we integrated IPR and TPR curves to find out the operating point of the wells. Then by intersecting turner model curve with the future IPR curves we predicted the year in which the problem of liquid loading may occur. This will help us in taking necessary precautions beforehand.
After liquid loading has occurred, there are different deliquification techniques to deload the well. They have been presented in this paper, which help in reinitiating gas production.
Liquid loading concept:
The gas which is the dominant phase initially in the well will carry the produced liquid present in the reservoir to the surface as long as the gas velocity is high enough to let it do so. A high gas velocity will cause mist flow in the well in which liquid is dispersed in the gas. This also means the liquid in the well will be low relative to the gas and will be carried out without accumulating downhole. This will result in a low pressure gradient in the well since there is more gas than liquid. As the gas velocity drops with time, the liquid carried out along with gas will start to drop and accumulate in the well, causing the pressure gradient to increase. Since high pressure gradient means a high hydrostatic pressure in the well, the reservoir pressure will encounter a much larger pressure against itself downhole. This will cause a decline in the gas rate and cripple gas production. Lower the gas rate falls, more liquid will be accumulated and this holdup will become a cycle, causing the well cease producing eventually.
Surface seismic offers a promising technique to monitor CO2 flood fronts during enhanced oil recovery process. Changes in seismic signature have been observed with CO2 flooding but quantification of the seismic signature with respect to subsurface saturation is still in its infancy. This study is focused on quantification of the variation in seismic parameters (velocity and impedance) with the change in subsurface fluid type and saturation.
The results of a laboratory study are presented where velocity and density were monitored as the pore fluids (formation brine and oil, and CO2) are replaced sequentially. All the experiments were performed at in-situ pressure conditions on plugs (Tuscaloosa sandstones) recovered from a well in a field currently undergoing CO2 flooding. The plugs used are characterized as fluvial (quartz~87%, clay~10%) and distributary channels (quartz~75%, clay~17%).
During brine flooding on dry samples, a decrease in P-wave velocity (~2%) was observed till 95% saturation and thereafter the velocity increases by 15% during the remaining 5% saturation. After attaining 100% brine saturation, oil was pumped to displace brine till irreducible water saturation was achieved. A linear drop of 4% in velocity was observed during this step. Liquid CO2 was injected to displace oil-brine system and a drop of 8% in P-velocity was observed. Associated changes in P-wave impedance due to change in pore fluid saturation are 25%, -5% and -8% respectively for the three flooding experiment. Biot-Gassmann modeling shows good agreement with experimental results for gas-brine and oil-brine system but not for liquid CO2 flooding.
4D seismic data set acquired over the same region is quantitatively interpreted based on these laboratory measurements.
One of the most critical capabilities of realistic hydraulic fracture simulation is the prediction of complex (turning, bifurcating, or merging) fracture paths. In most classical models, complex fracture simulation is difficult due to the need for a priori knowledge of propagation path and initiation points and the complexity associated with stress singularities at fracture tips.
In this study, we follow Francfort and Marigo's variational approach to fracture, which we extend to account for hydraulic stimulation. We recast Griffth's criteria into a global minimization principle, while preserving its essence, the concept of energy restitution between surface and bulk terms. More precisely, to any admissible crack geometry and kinematically admissible displacement field, we associate a total energy given as the sum of the elastic and surface energies. In a quasistatic setting, the reservoir state is then given as the solution of a sequence of unilateral minimizations of this total energy with respect to any admissible crack path and displacement field. The strength of this approach is to provide a rigorous and united framework accounting for new cracks nucleation, existing cracks activation, and full crack path determination (including complex behavior such as crack branching, kinking, and interaction between multiple cracks) without any a priori knowledge or hypothesis.
Of course, the lack of a priori hypothesis on cracks geometry is at the cost of numerical complexity. We present a regularized phase field approach where fractures are represented by a smooth function. This approach makes handling large and complex fracture networks very simple yet discrete fracture properties such as crack aperture can be recovered from the phase field. We compare variational fracture simulation results against several analytical solutions and also demonstrate the approach's ability to predict complex fracture systems with example of multiple interacting fractures.
Troll is a large subsea development offshore Norway. Oil is produced to Troll B and Troll C platforms from 120 long horizontal subsea wells completed in a thin oil column. Oil production is optimized within the gas handling capacity at the platforms and the challenge is to drill and complete the wells in a way that gas does not have an easy access into the well. Troll has focused on developing and implementing inflow control devices that limits gas coning. An autonomous inflow control device, the RCP valve, has been developed by Statoil and implemented at the Troll field. The purpose of the RCP valve is to restrict gas compared to oil. The valve adjusts the choking of the fluids depending on which phase (oil or gas) being produced. Currently three wells have been completed with RCP valves. Reservoir simulations as well as production experience show a significant increase in oil production. It is observed that a well completed with RCP valves has a significantly lower gas oil ratio development compared to other Troll wells.
Multistage hydraulic fracturing is one of the key technologies affording the successful development of unconventional reservoirs. Transverse fracturing of horizontal wells has become the standard for development of these plays, allowing commercial exploitation of what were once considered uneconomic resources.
The primary goal of the completion in these ultra-low permeability formations is to provide a conductive path to as much rock as possible, through the use of multistage hydraulic fractures along a horizontal lateral. This requires two separate, yet complimentary strategies - a wellbore with optimal length and completion hardware, and multiple hydraulic fractures with optimal conductivity. Most completions engineers have a good understanding of their wellbore and completion hardware; however, many do not have the same level of knowledge of their hydraulic fractures. This leads many to incorrectly assume that fracture conductivity is unimportant. However, the fracture provides the critical link between the formation and the wellbore; without a durable fracture, the completion will fail.
This paper will present a technique to assess the realistic conductivity of the fracture at downhole conditions, describe the relationship between conductivity and productivity, and evaluate the impact of treatment optimization on economics. Use of this approach allows engineers to design their fracture stimulation to maximize the economic potential of their well.
Laboratory data are presented which demonstrate the impact of downhole conditions on proppant performance, including fines migration, elevated temperatures and embedment. In addition, fracture modeling and actual field results will be presented to illustrate the optimization process. Case histories showing the successful implementation of this method will be provided in unconventional gas (Haynesville), a liquids rich formation (Eagle Ford) and an unconventional oil reservoir (Bakken).
This paper will serve as a resource to those engineers who wish to gain a better understanding of hydraulic fractures or desire to maximize the economics of their completions in unconventional plays.