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Herrera, Delimar C. (Schlumberger) | Ghani, Ahsen (Dubai Petroleum Establishment) | Senan, Faisaal (Dubai Petroleum Establishment) | Byrne, Sean (Dubai Petroleum Establishment) | Mellor, Andrew (Dubai Petroleum Establishment)
After fast-tracking exploration success into an early production opportunity, Dubai Petroleum Establishment (DPE) recognized directional-casing-(and-liner)-while-drilling (DCWD) technology as enablers to optimizing the full field development of a thin oil rim within an interbedded steeply dipping reef build-up, just below the Nahr Umr Shale. The field development strategy was to land the well as close to the roof of the reservoir as possible and target the attic oil. This required entering the reservoir at higher inclinations and hence drilling the Nahr Umr Shale (cap rock for the reservoir) at more than 80° inclination. The regionally well-known borehole stability issues related to drilling the Nahr Umr Formation at high inclinations (and especially at azimuths that compound issues associated with in-situ stresses) presented a significant challenge for this field development.
The objective of this paper is to share an innovative and successful solution which was implemented to mitigate or eliminate the potential issues associated with drilling operations through problematic and unstable formations at high angles (almost horizontal).
An extensive engineering process was conducted involving different teams across the operator and the CWD service provider. The process included bottom hole assembly (BHA) drilling dynamics modelling using 4D time-based calculations and the typical drilling engineering calculations (torque and drag, hydraulics, alternating stress, etc.) to enhance the drilling performance during the drilling campaign. As an example, in one of the wells, the team drilled an interval in excess of 1200-ft, reaching the new world-record depth of 12,481-ft_MD, whilst meeting the operator's expectations in terms of rate of penetration (ROP), steerability of the directional BHA (achieving dogleg severity values higher than 4°/100ft), and flawless execution.
The paper shows the methodology followed by the drilling team to evaluate the feasibility of the application, the challenges and lessons learnt, and the innovative solutions (telemetry, mud system, logging while drilling [LWD], motor design, underreamers, etc.) which were put in place to optimize the process over the course of the first six jobs in this new field.
The DCWD technology enabled the well construction requirement of drilling an unstable shale on a high inclination trajectory (from 60° to 88° inclination), minimizing the stuck-pipe risk and typical unplanned time (NPT) associated with hard reaming, tight spots, and stuck pipe, and eliminating the additional 8 ½-in. hole requirement.
The application allowed the operator to enhance the wellbore construction process and eliminated the requirement for an additional short 8.5-in. hole section, which then had to be cased off with a 7-in. liner to isolate the problematic formations. This represents a revolutionary change compared with the way that this challenge has been historically tackled by the operators in the Middle East (including limiting the inclination to a maximum 35°-40° or using oil-based mud [OBM] fluids with extremely high density that increases the chances of losses in the above formations, among others).
The potential time savings due to the elimination of an additional interval to cover the problematic shale are estimated in excess of four days. In addition to the time savings, the operator has significantly reduced the associated cost for the BHA lost in hole (LIH) while drilling through the problematic shale without limiting the maximum inclination before landing in the target reservoir. This also creates a positive impact on the directional requirements for the horizontal-producing section (which can now be drilled in either 8 ½-in. and or 6-in. to address reservoir mapping and production conformance requirements).
Abstract A powerful new tool for unconformity identification in a range of geological environments is presented together with very strong evidence of its utility. Commonly in an exploration setting correct sequence interpretation has taken years and multiple detailed studies, now with the new tool it can be done quite easily in near real time. Recognition of unconformities in boreholes, particularly where correlation with outcrop is not available, traditionally relies on paleontological methods, normally palynology or micropalaeontology and correlations between wells where sections of the observed sequence are missing. Observations in recently drilled wells in Dubai have provided evidence for another useful tool. While drilling Well A, bulk rock phosphate concentrations were obtained in near real time while drilling using X-ray fluorescence (XRF). These were then plotted against well depth. Phosphate values were taken as indicators of long duration and high intensity of organic production or conversely a low rate of sedimentation. Unconformities were marked by significant and obvious phosphate peaks while drilling in a marine sequence. Higher than average concentration of phosphates in marine environments during periods of non-deposition or very slow deposition have been known for some time but their use as markers for unconformities while drilling has not been widespread due to the practical difficulties with sample analysis. With advances in XRF technology routine wellsite XRF analysis services are now available. Plots of phosphate concentrations in Well B which was drilled through a sub-aerially deposited sequence also showed phosphate peaks, some of which correlated with known and recognisable unconformity surfaces. Further evaluation, particularly comparison with palynology data, showed that the phosphate peaks which did not correlate with known unconformities indicated previously unrecognised unconformities. Phosphate peaks on unconformity surfaces in sub-aerially deposited sequences have not, as far as the authors can determine, been previously recognised. Well C is an older well which penetrated a similar sub-aerially deposited sequence to Well B with no XRD analyses available. Correct interpretation of the Well C sequence was not possible until the key points were derived from the more complete Well B data. Evidence is presented showing that phosphate peaks are practical and useful indicators of unconformities in near real time, especially when interpreted with other geological information. An example is also given of an unconformity which displays no phosphate peak together with an explanation as to why there is no peak. In an exploration setting analysis of phosphate trends can significantly enhance and simplify sequence and palaeoenvironmental interpretation and understanding of regional tectonics thus providing greater insight when planning follow up wells leading to a higher success rate. As such it is a new and novel exploration tool with a potentially high economic value.
Sales da Silva, Aguida (Dubai Petroleum Establishment) | Schebath, Dominique (Dubai Petroleum Establishment) | Phyoe, Thein Zaw (Schlumberger) | Kapoor, Saurabh (Schlumberger) | Herrera Albuja, Eduardo (Schlumberger) | Sajid, Muhammad (Schlumberger)
Abstract The objective of a cementing operation is to achieve a long-term well integrity by providing good zonal isolation. In cementing operations in the northern part of the United Arab Emirates (UAE), thick salt formations, potential high-pressure zones, lost circulation zones and planned high pressure casing test added to the complexity of the cement job. The presence of 3,000-ft or thicker salt formation posed a key challenge. The chemically reactive salts in the salt sections affects slurry placement and hydration. Salt from formation can be incorporated into cement slurry while placement and adversely affects the fluid loss, rheology, and setting characteristics. Thus, first, the cement system needed to be designed to be tolerant of such effects. Also, high pore pressure was expected while drilling so the planned mud density varied from 15.5 ppg to 18 ppg. The highest cement slurry density of 19.2 ppg was required to cover this wide range while maintaining the density hierarchy requirement for optimum placement. Additionally, a high-pressure test planned after the casing was set resulted in additional stresses, which also posed substantial risks to the integrity of the cement sheath. A methodical approach was applied by first following the standard cementing practices and then categorizing the key factors in overcoming field specific challenges. Stress analysis using advanced software helped to identify the needed mechanical properties for the flexible and expanding cement system to remain intact under extreme pressure changes. After the in-depth lab testing, a fit for purpose compatible for placement against salt formation cement system was introduced. The use of engineered lost circulation fibers in the cement system would help to mitigate the losses during the cement job. The engineered high-density salt compatible flexible expandable cement system was designed to provide the desirable outcome to the complex challenges. Comprehensive lab testing along advanced zonal isolation software helped in successful first-time execution. The first-time application of this salt compatible flexible and expanding cement system has proven to be a robust solution for the cementation and could be the basis of design for all future wells industry-wide.
Bukovac, Tomislav (Schlumberger) | Akbari, Aulia (Schlumberger) | Gurmen, Nihat M. (Schlumberger) | Mehrotra, Nagendra (Dubai Petroleum Establishment) | Alabi, Ibrahim (Dubai Petroleum Establishment) | Orellana, Roland (Dubai Petroleum Establishment) | Arcano, Nelson Suarez (Dubai Petroleum Establishment)
Abstract To overcome the challenges specific to unconventional reservoirs that are being targeted across the Middle East region a synergy of unconventional technologies is needed. Fracturing fluids are one of the critical components of multi stage proppant fracturing solution when targeting extreme HPHT reservoirs while aiming to preserve freshwater. The objective of this paper is to reveal the performance of unique fracturing fluids that have been recently tailored and applied to tackle tight and unconventional reservoir challenges. Three very different unconventional: polymer-free, carboxymethyl hydroxypropyl guar (CMHPG) and poly-acrylamide based fracturing fluids are presented in this work. They have been field-tested and recently successfully applied in the tight and unconventional reservoirs of UAE as well as the Middle East and Asia. These fracturing fluids collectively address the full spectrum of existing and future reservoir target bottom-hole temperatures ranging from 50 degF up to 450 degF. The unique chemistry characteristics for each of the fluids will be elaborated together with laboratory test results that will include compatibility, rheology and other qualification tests. Furthermore, results of extensive qualification tests performed to address specific local challenges will also be presented. All three fracturing fluids were effectively applied leading to treatment success and proving their performance in extreme reservoir temperature, stress or operational environment that demands high-efficiency. Each fluid proved compatibility with used mixing water and reservoir fluids tested. These fracturing fluid types can be continuously mixed simplifying operation, reducing fracturing equipment layout and minimizing waste. All these improvements are critical in an offshore operating environment. Polymer-free and CMHPG based high viscosity fluids are formulated with sea water to minimize environmental impact. Furthermore, these fluids are continuously mixed with seawater addressing the conventional fracturing fluid logistic constraints offshore. These key improvements made massive offshore and multi-stage proppant fracturing treatments technically and economically feasible. The novel unconventional fracturing fluids elaborated in this paper offer a set of unique technical capabilities that did not exist previously. These three fluids are critical technology enablers and they are part of a multi-disciplinary, integrated technical collaboration project aiming to efficiently and effectively address local complex subsurface conditions and stringent economic requirements of remote offshore operations.
Mehrotra, Nagendra (Dubai Petroleum Establishment) | Moreira, Luis (Dubai Petroleum Establishment) | Alabi, Ibraheem (Dubai Petroleum Establishment) | Thompson, Hamish (Dubai Petroleum Establishment) | Arcano, Nelson Suarez (Dubai Petroleum Establishment) | Freile, Juan Pablo (Dubai Petroleum Establishment) | Bruseth, E. E. (Packers Plus Energy Services)
Abstract Given the recent unique economic challenges and continued need to optimize lower completions, a new approach was successfully implemented offshore by Dubai Petroleum Establishment (DPE), an oil operator headquartered in Dubai, United Arab Emirates (UAE). In the unconventional carbonate source rock Shilaif formation at 8,400 ft true vertical depth (TVD), hydraulic fracturing including proppant was coupled with an openhole multistage (OHMS) ball drop sliding sleeve technology –– a first for offshore completions in the Middle East. This paper will discuss previous completion designs including acid stimulations and most recently an un-cemented completion liner using hydraulic fracturing and proppant. Having matrix-acidized the conventional carbonate formation on previous wells, DPE looked toward improving their stimulation methods for tight unconventional source rock to further enhance the recoverable reserves and continue to optimize the completion. Key factors evaluated before deciding to use the ball-drop activated sliding sleeves over the traditional plug and perforate (PnP) method of completion were benefits to safety, recovery potential, previous positive experience with the completion method, ease of installation, the ability to continuously pump the stimulation without shutting down (a large benefit in offshore completions) and a significant cost saving. A new technology was also implemented to confirm in real-time that the sliding sleeves functioned. Until now, surface pressure responses were the only indication the sleeves had functioned. This new technology allowed for real time sleeve shift verification that was independent from the usual pressure signature. The application required a unique, fit for purpose, completion system due to the demanding environment created by both the offshore conditions and the 15,000 psi differential rated equipment requirements for high stress unconventional rock. The tools were engineered, manufactured, and installed in a narrow timeframe that met the demanding offshore rig schedule. The system was then stimulated with a maximum surface treating pressure up to 10,000 psi in a continuous pumping operation. A total of 8 stages were successfully hydraulically stimulated with proppant without any major issues. All balls landed and shifted their respective sliding sleeves which were verified by real time pumping pressure response monitored at surface and independently with the new well monitoring technology used on this well, transmitting data to the main office. The technologies, methods and procedures presented in this paper are intended to show how DPE is leading the way in the region in reducing completion costs while safely working offshore. The completion solutions engineered and implemented for the placement of these offshore multistage proppant fracture stimulations have allowed DPE to unlock a significant volume of hydrocarbon reserves in the Dubai acreage, if not in the whole region.
Chemin, Frederic (Dubai Petroleum Establishment) | Freile, Juan Pablo (Dubai Petroleum Establishment) | Moreira, Luis (Dubai Petroleum Establishment) | Mehrotra, Nagendra (Dubai Petroleum Establishment) | Alabi, Ibraheem (Dubai Petroleum Establishment) | Thompson, Hamish (Dubai Petroleum Establishment) | Arcano, Nelson Suarez (Dubai Petroleum Establishment) | Bukovac, Tomislav (Schlumberger)
Abstract The development of offshore unconventional reservoirs through hydraulic fracture stimulation has been debated for more than a decade. Attempted in isolated cases in small scale, such operations have been considered too complex, expensive, risky, and finally not economically attractive compared to other development opportunities. Technological breakthroughs in hydraulic fracturing in the past decade have enabled the renaissance of the oil and gas industry with the development of tight and source rock reservoirs mainly in onshore applicationsland in North America. New and dramatically improved operational efficiency standards have been set for fracturing in the last years. However, the same efficient operational set up, successful in onshore North America, cannot be directly emulated in an offshore environment due to limited space, more complex logistics, cost and environmental constraints. DPE, oil operator headquartered in Dubai-UAE, was able to overcome these challenges successfully and in 2016 drilled, completed and produced the world's first offshore horizontal multi-stage proppant fractured well that targeted a tight carbonate source rock, the Shilaif Formation at 8,400ft true vertical depth, source rock for most of the oil produced in Dubai. The successful concecusion of this project has allowed DPE to unlock a very significant volume of reserves in the Dubai acreage and possibly in the whole region. Albeit being one of the most complex and largest offshore stimulation jobs ever attempted, it was executed with minimum environmental impact; no freshwater was used, the post-frac flow-back was performed in a closed loop system where clean-up and production testing packages were specially designed conveying the flow-back fluids directly to the offshore production facility. The use of a modular type frac-package with continuous seawater mixing capability minimized environmental impact and avoided any freshwater consumption. The stimulation was executed from a lift boat, less sensitive to maritime conditions, which accommodated equipment and crews for continuous wellsite operation. Eight proppant fracturing treatments were performed in 48hr. Wellbore conditions and petrophysical data acquired while drilling allowed for a robust multi-stage open-hole completion design. The eight stage proppant fracturing treatment was engineered using channel fracturing techniques with 560,000 lb of proppant. This specific technique was applied to optimize proppant volumes and operational footprint while limiting screen-out risk in this complex reservoir stress setting and maximizing frac conductivity. This paper describes wellbore, completion, stimulation, clean-up and production testing design and planning that lead to this important technical success. It also highlights the potential of Dubai's offshore Shilaif resources. DPE's reservoir appraisal strategy followed during phase-one (2012-2016), potentially has opened the door to a new oil producing era in Dubai. This remarkable operation performed in the UAE with cutting edge technology and innovative operative integration was able to set a new efficiency benchmark, not only for well completion and fracturing operations within Middle East but also for offshore in general.
Aslanyan, Arthur (TGT Oil & Gas Services) | Aslanyan, Irina (TGT Oil & Gas Services) | Karantharath, Radhakrishnan (TGT Oil & Gas Services) | Matveev, Sergey (TGT Oil & Gas Services) | Skutin, Vasilii (TGT Oil & Gas Services) | Garnyshev, Marat (TGT Oil & Gas Services) | Bevillon, Damien (Dubai Petroleum Establishment) | Mehrotra, Nagendra (Dubai Petroleum Establishment) | Suarez, Nelson (Dubai Petroleum Establishment)
Abstract Wellbore fluid flow profiles in both producers and injectors tend to change over time due to preferential depletion, formation damage, cross-flow, channelling or tubing or casing leaks. These changes can result in excess water production through channelling, coning, non-uniform water breakthrough (fingering) or out-of-zone injection – all leading to uneven flow, pressure and sweep profiles. Ignoring these complications can result in missing key points on reservoir behaviour, selecting wrong units for a 3D full-field flow model or misleading redevelopment planning. Therefore, it would be logical to check for changes in flow geometry before embarking on costly workovers, recompletion or infill drilling programs. This paper compares and integrates the results of conventional Production Logging Tool (PLT) surveys that use spinners and multiphase sensors with those acquired by reservoir-oriented production logging surveys employing a combination of Spectral Noise Logging (SNL) [1,2] and High Precision Temperature (HPT) Logging [3–5]. PLT and HPT-SNL produce similar results when wellbore and completion conditions are good but they may differ dramatically in cases of non-uniform formation damage, channelling behind pipe or plugging of perforations by scale. Generally, HPT-SNL would assess the flow geometry and invaded zones of the reservoir while PLT would point out where fluid enters or leaves the wellbore or tubing. The paper provides case studies from a mature offshore waterflooded field producing a mix of oil, gas, formation water and injection seawater, which complicates the identification of flow geometry and invasion zones and represents a challenge for reservoir engineers in developing proper drilling or workover programmes to target residual reserves [6, 7]. The HPT-SNL-PNL surveys and further studies described here led to successful workovers and drilling. The redevelopment results can be easily assessed by decline curve analysis. Introduction Since 2007, Dubai Petroleum Establishment (DPE) has performed more than 150 integrated PLT-HPT-SNL surveys to monitor vertical wellbore injection and production profiles that resulted in valuable and often surprising findings including unexpected water breakthrough intervals, bypassed oil zones and layers and water channelling behind casing in producers and injectors. These findings, in turn, led to a better understanding of how water propagated through reservoir from injectors to producers and were used to calibrate a 3D full-field flow model and identify optimum infill drilling locations for the redevelopment of the highly fractured crestal area of the field.
Suarez, Nelson (Dubai Petroleum Establishment) | Otubaga, Ademola (Dubai Petroleum Establishment) | Mehrotra, Nagendra (Dubai Petroleum Establishment) | Aslanyan, Arthur (TGT Oil and Gas Services) | Aslanyan, Irina (TGT Oil and Gas Services) | Khabibullin, Murat (TGT Oil and Gas Services) | Wilson, Michael (TGT Oil and Gas Services) | Barghouti, Jamal (TGT Oil and Gas Services) | Maslennikova, Yulia (TGT Oil and Gas Services)
Spectral Noise Logging (SNL) can provide information on reservoir flow units behind one or multiple barriers, which is beyond the spinner capability. The SNL tool is designed to record a high-resolution noise pattern in a wide frequency range, normally generated by fluid or gas flowing through porous media and the wellbore. Noise pattern recognition is critical to differentiate between formation flow and wellbore flow.
SNL complements conventional production logging techniques by providing significant information that enhances reservoir flow characterisation. The tool design, data acquisition and advanced processing allow the location of active flow units and differentiation between flows through the reservoir matrix, fractures, high-permeability features, behind-casing channels and wellbore completion components.
Thorough analysis of active flow streaks helps to monitor sweep efficiency and identify bypassed oil regions.
Reservoir matrix flow noise remarkably correlates with porosity distribution. Therefore, it is an effective way to verify porosity and permeability models. This paper presents five field cases of SNL surveys performed during 2009–2011 in wells operated by Dubai Petroleum Establishment. These cases illustrate the allocation of injection by zone with rates below the spinner threshold, evaluation of the reliability of plugged perforations, and description of the behindpipe flow geometry. The paper also contains an introduction to SNL tool operation and noise data processing principles.
Wireline formation pressure testing has been routinely used as a valuable reservoir characterization tool and its results are generally well regarded. On the other hand, LWD formation pressure testing, initially introduced primarily as a drilling safety and ECD optimization tool, has yet to fully prove its effectiveness in reservoir evaluation, due to perceived data acquisition challenges. Today, re-entry drilling is used in many aging oil and gas fields to target the remaining hydrocarbon. Formation pressure, fluid gradients and the determination of whether or not compartments are in communication are important information when analyzing such a reservoirs in real time for optimum wellbore placement. The cost efficiencies of acquiring formation pressure data while drilling are becoming more influential in the operator’s technology selection process, but should not come at the cost of reduced data accuracy or usability.
This paper discusses new techniques and technologies that facilitate gaining a better understanding of the subsurface while drilling. These include a smart test function, which reduces formation shock while pressure testing in microDarcy formations and avoids sanding in highly unconsolidated formations. Performing optimized test sequences improve the accuracy of the pressure and mobility data and lead to higher operating efficiency. Also, LWD pressure testing on wired pipe yields a data density previously only found on wireline. The introduction of extended test times of up to 40 minutes increases the scope of LWD pressure testing into traditional formation pressure testing applications, such as compartmentalization evaluation or fluid gradient analysis. Longer test times and testing on wired pipe precede future fluid sampling while drilling. Benefits for drilling and subsurface teams are equally important and the reason why LWD formation testing has become a cross-functional discipline. Case Histories from the United Arab Emirates (UAE) and Asia Pacific will be used to highlight the recent technology advances and applications.
Dubai Petroleum Establishment (DPE) was initiated in 2007 when some of the very first oil field concessions were handed back to the government of Dubai. The first concession was obtained and held by Dubai Petroleum Company (DPC) in 1961. ConocoPhillips, Total, Repsol YPF, RWE Dea and Wintershall also operated the fields in subsequent concessions and helped building the new Dubai. After a development and production period lasting more than 40 years, fields like Rashid and Falah were still producing effectively and economically. For future production plans, formation pressure is an important tool in calibrating the reservoir model, and the obtained mobility is a good indication of whether the formation matrix has potential for producibility of the fluids. The present use of a Formation Pressure testing LWD tool is mainly to identify depleted reservoir packages, and reservoir continuity. The ability to do this while drilling greatly reduces the costs and risks of the operation.
The carbonate reservoirs in offshore Dubai are characterized by complex textural heterogeneity. This leads to a permeability variation that is the controlling factor in reservoir production.
This case study shows how the use of new seismic technology allows the recording of good-quality surface Various vintages of seismic data exist in the area of seismic data in an area of complex geology that has interest, including a 2D dataset recorded in the mid 1980s historically provided poor seismic data. The enabling and a large 3D survey recorded in 2002. The 2D data are, in technology was 80,000-lb peak force vibrators using an general, of better quality than the 3D data. As a result, the energetic low-frequency sweep recording into densely new survey parameters were loosely based on the best 2D sampled single-sensor accelerometers. The study area is in line recorded in the area.