Al-Otaibi, Yousef (Kuwait Oil Company) | Al-Mutawa, Majdi (Kuwait Oil Company) | Bloushi, Taha (Kuwait Oil Company) | Fidan, Erkan (Kuwait Oil Company) | Sharma, Siddhartha (Kuwait Oil Company) | Pradhan, San Prasad (Kuwait Oil Company) | Manimaran, Palaniappan (Kuwait Oil Company)
Optimization of permanent liner completions in the North Kuwait Jurassic Gas (NKJG) reservoirs has been an ongoing challenge progressed on a steep learning curve within the last decade. Various completion options are field-tested in determining the optimal completion hardware and activation methodology. The asset's objectives have been multi-dimensional: preserve natural fractures, minimize formation damage, segregate, stimulate and activate optimally, while installing permanent completions hardware efficiently, which can withstand 15,000-psi differential pressure at high temperature and sour gas environment and sustain production for the well life of over 20 years.
NKJG faces the enormous task of increasing the hydrocarbon production potential by over 200% within a short time period. The reservoirs are high-pressured and high-temperature (HTHP) gas condensate assets with tight matrix properties (i.e. <0.1 mD permeability), in variation with naturally fractured sections within flow-zones separated into eight segments. Preserving the natural fractures, removal of near wellbore damage and segregating flow-zones based on lithology and critical reservoir properties are important especially in peripheral subsurface locations, where the realization of full reservoir potential is not only essential for production success, but also required for appraisal of boundary conditions. For realizing these objectives, the asset custom-designed a multi-stage completion system with hydro-mechanical liner hanger packer, open-hole packers, hydraulic anchor and multiple frac ports set and activated as a drop-ball system. Due to the high completion loads, differential body and packer rating are manufactured to 15,000 psi using corrosion resistant alloy throughout, with the PBR and seal-bore assembly designed to withstand differential pressures and contraction during multiple fracturing events.
Custom-designed multi-stage completion assembly (MSC-HP) was successfully installed, sequentially hydraulic-fracced and commingle-tested on flowback. Customized operational guidelines were established including a pre-set success criterion, openhole and caliper log sequences, tie-back cementation and subsequent clean out trips, followed by hole conditioning and reamer runs to compute the final drag and friction forces. Differential sticking risks were mitigated by avoiding the "pressure ramps" exacerbated by differential depletion evident in the area. Reservoir was segmented in three distinct intervals to maximize flow potential. As a result, the asset's objectives were successfully met, with the additional benefits of proving multiple zone activation, each with a complicated sequence of operational events, performed sequentially in four days.
This paper documents the project cycle from successful planning and design, to installation and execution phases of the MSC-HP in peripheral deep NKJG asset. Key learnings and critical factors, which led to the successful well results in spite of less favorable subsurface location are summarized. Added complications due to the severe NKJG specs will be discussed as the number of global analogues is scarce leading to limited opportunities for the industry to learn from in unconventional/conventional mix layered carbonates.
Al-Othman, Mohammed (Kuwait Oil Company) | A-Matrouk, Yousef (Kuwait Oil Company) | Ahmed, Zamzam (Kuwait Oil Company) | Ashkanani, Meshari (Kuwait Oil Company) | Buhamad, Ali (Kuwait Oil Company) | Al-Dousari, Mohammad (Kuwait Oil Company) | Ahmed, Abdul-Samad (Kuwait Oil Company) | Fidan, Erkan (Kuwait Oil Company) | Mahmoud, Wael (Schlumberger) | Liu, Hai (Schlumberger) | Salem, Abrar (Schlumberger) | Nikolaev, Max (Schlumberger)
Heterogeneity across the producing interval is typical in oil and gas wells; it is rare to find uniform production distribution or fluid injection across a substantially long interval. Hence, diversion during matrix acidizing is critical, especially if the downhole pressure and/or temperature are high.
In two Kuwait Jurassic fields, two wells were completed in an over 100 ft producing interval across a carbonate reservoir. Reservoir temperature is 280°F, and the estimated reservoir pressure is 11,000 psi. Multiple matrix acidizing trials to enhance well productivity have been performed with conventional diversion techniques and, as indicated by the surface pressure response, were not effective. This requires an adequately engineered near wellbore diversion system that can overcome the challenge of these bottomhole conditions and form a uniform production distribution across a substantially long heterogeneous interval.
A new methodology was applied in two Jurassic wells that combined a multimodal blend of biodegradable particulates and fibers as a chemical diverter, and emulsified acids as main fluids for a matrix stimulation. In each diversion stage, the change in surface pressure ranged from 800 to 1,000 psi after the diversion pill hit the perforation tunnel. Moreover, a clear signature of diversion was demonstrated in the instantaneous shutin pressures. In another Kuwait field, the diversion pill was tested by using injectivity logging tests to monitor the changes in injectivity across the perforated interval during an acid fracturing treatment in comparison to the earlier injection profile. A remarkable change in injection was observed and a total of 80% change in the injection profile was quantified from before and after the diversion.
The diversion pill is relatively small in volume and is easy and safe to handle. Fibers help to maintain the carrying capacity and allow safe landing of the biodegradable material to the formation face. Only a few barrels are required to plug the opened or stimulated interval, and the method allows the following stimulation stage to treat the subsequent interval.
The first well revealed a 330% and 110% production increase in gas and oil rates, respectively. The production was set as one of the highest producers in the field. The second well yielded a 320% increase in total production, which set the highest record for the field. The new method is proved to be highly effective in terms of wellbore coverage, and highest production records in the field after matrix acidizing treatments.
Sierra, Leopoldo (Halliburton) | Alboueshi, Alaa Eldine (Halliburton) | Elmofti, Mohamed (Halliburton) | Eid, Walid (Halliburton) | Sadeddin, Salma (Halliburton) | Allam, Ahmed (Halliburton) | Al Othman, Mohamed (KOC) | Ahmed, Zamzam (KOC) | Fidan, Erkan (KOC) | Al-Zaidani, Ibrahim (KOC) | Nilotpaul, Neoq (KOC) | Ashkanani, Meshari (KOC) | Buhamad, Ali (KOC) | Al-Dousari, Mohammed Abdullah (KOC) | Ahmed, Abdul-Samad Mohammed (KOC) | Al-Matrouk, Yousef (KOC)
The case history presented in this paper describes the performance of an acid fracture intervention in a HP/HT well where, because of a number of problems encountered during the well construction stage, this intervention was the last procedure considered to evaluate the productivity of a Marrat formation well. In view of the stimulation challenges encountered, the architecture of the wellbore, and the intervention stimulation requirement to evaluate the productivity of the horizontal well completed in the Marrat formation, it was necessary to change the proppant fracture stimulation technique originally planned. Instead, it was decided that a selective acid fracture stimulation would be performed in the prospective part of the horizontal section where three long perforation clusters had been placed. Acidizing fracture stimulation was performed in one intervention using a next-generation liquid and soluble solid diversion system that enabled the generation of one selective fracture per perforation cluster. The planned acidizing fracture stimulation process was implemented properly in the field in accordance with the design constraints. The reactive fluid system diversion and the generation of a new fracture when the diversion system reached the perforation were clearly observed. The post-acid fractured well productivity index (PI) showed the high quality of the stimulation performed in a challenging environment, demonstrating the effectiveness of the new diversion system for creating selective fractures in a horizontal wellbore with multiple perforation clusters. Considering the well's architecture, HP/HT nature, and single intervention requirement, the case study documented in the paper can be helpful in the decision-making process when selecting a proper stimulation technique for challenging conditions. The effectiveness of the new diversion systems is also discussed.
Ahmed, Zamzam (Kuwait Oil Company) | Al-Otaibi, Yousef (Kuwait Oil Company) | Bloushi, Taha (Kuwait Oil Company) | Fidan, Erkan (Kuwait Oil Company) | Sharma, Siddhartha (Kuwait Oil Company) | Pradhan, San Prasad (Kuwait Oil Company) | Al-Mutairi, Mubarak (Kuwait Oil Company) | Al-Failakawi, Abdul Aziz (Kuwait Oil Company) | Shaikh, Ahmed Karim (Shell Kuwait Exploration and Production) | Quint, Edwin (Shell Kuwait Exploration and Production)
The HPHT, sour, deep, fractured and not so fractured carbonate Jurassic formations within the North Kuwait cluster of fields present extraordinary challenges in driving towards an optimized field development that maximizes liquid recovery and meet the gas production aspirations for the state of Kuwait.
The Middle Marrat reservoir has been developed to date with cased and perforated liner completions across the 500- 700ft pay. However due to the high permeability contrast between the different reservoir flow units, the low permeability zones are typically not contributing. This is further exasperated with the inability to effectively acid stimulate large proportion of the net pay with a single stage bullhead treatment especially when the contrast in permeability between the various flow units is higher than one order of magnitude.
Key to successful reservoir management of the Middle Marrat whilst maximizing well capacity to meet the production aspirations is to implement a completion and stimulation strategy that maximizes flow contribution from as much of the net pay as possible. Single stage bullhead matrix acid stimulation treatments like those executed in the past will only stimulate the top decade of permeability. The current 4-1/2" cemented completion ‘plug and perf’ standard will require intensive well intervention to set and drill out plugs in order to selectively stimulate individual zones.
To develop an alternative completion and stimulation strategy for developing Middle Marrat, the first 4-1/2" multistage ball activated sleeve completion system has been deployed successfully in a Middle Marrat deviated development well. 2 out of 3 stages installed have been acid stimulated and flow tested showing excellent results. The operational experience and learnings acquired from the project have provided the necessary confidence to the organization to deploy the technology in tight gas and unconventional reservoirs within North Kuwait, but also challenge the existing cemented ‘plug & perf’ completion and stimulation approach for the development of the more conventional Middle Marrat reservoirs.
Kanneganti, Kousic (Schlumberger) | Mahesh, Arathi L. (Schlumberger) | Barasia, Ankur (Schlumberger) | Cabrera Salavarria, Jose Ramon (Schlumberger) | Dananjaya Wiryoutomo, Marenda (Schlumberger) | Mohamed Abdul Samad, Zamzam (Kuwait Oil Company) | Fidan, Erkan (Kuwait Oil Company) | Aziz Al-Failakawi, Abdul (Kuwait Oil Company)
The deep high pressure/high temperature (HPHT) dolomite formation in Northern Kuwait has been a challenge with varied production, attributable to reservoir heterogeneity. Due to the tight nature of these rocks, matrix acidizing may not produce desired effects, thus requiring hydraulic fracturing to produce at economic rates. However, the tectonic setting in high stress environment has resulted in subpar success and inconsistent results from stimulation treatments in matrix and hydraulic fracturing applications.
This paper presents a multidisciplinary approach to address the limited success in the Northern Kuwait Dolomites. An integrated petrophysical evaluation of the current wells will be followed with multi-well Heterogeneous Rock Analysis (HRA), to evaluate the reservoir heterogeneity across the field and identify the ‘sweet spots’ for future drilling locations. Evaluation and lessons learnt from the past stimulation treatments, will be used to understand geo-mechanical challenges and to help calibrate the Mechanical Earth Model (MEM) for implementation in the future wells. Finally, using a reservoir-centric stimulation design tool, stimulation type (acid fracturing vs proppant fracturing) and stimulation design optimization for future wells will be developed.
A reservoir-level petrophysical evaluation of the existing wells was performed and compared to understand the reservoir heterogeneity vis. a vis. production potential. Multiple rock classes were identified within the tight dolomite interval, with a gross thickness of ~250 ft. Starting with log based MEM, results from the image log interpretation and the field observations/measurements from fracture diagnostic tests (Decline analysis, Calibration injection) were used in calibrating the MEM and mapping the Completion Quality (CQ) heterogeneity across the field. This has led to a reservoir-level understanding, which can enable planning optimal well locations, target interval and subsequent well placement/completions methodology. Finally, using the reservoir-centric design tool, an optimum design to effectively stimulate the ultralow-permeability dolomites was determined. The optimization workflow did not only include a single-faceted approach of fracture modeling, but also encompassed a production forecast using the integrated numerical reservoir simulator. Lessons learnt from the optimization workflow were further extended to designing horizontal wells (landing point, trajectory for optimal stimulation geometry), and hence to aid in field development strategy.
Using the multidisciplinary unconventional workflow, the heterogeneity in reservoir quality and completion quality was evaluated, both along the wellbore and spatially. In essence, we found that natural fractures along with high Critical Net Pay (CNP) allows you to vertically connect with good RQ and thus, is required for success in these tight reservoirs. Following which, reservoir-centric stimulation design tool enabled optimization of completion and stimulation design in a holistic approach, to maximize appraisal and production opportunities.
Al-Zaidani, Ibrahim Mahamed (Kuwait Oil Company) | Barasia, Ankur (Schlumberger) | Al-Failakawi, Abdul Aziz Haider (Kuwait Oil Company) | Fidan, Erkan (Kuwait Oil Company) | Sharma, Siddhartha Shankar (Kuwait Oil Company) | Samad, Zamzam Mohammed Abdul (Kuwait Oil Company) | Khayan, Andre (Schlumberger)
Appraisal program of the deep gas/light oil from unconventional reservoirs in North Kuwait is strategically important to secure the challenging hydrocarbon production targets of Kuwait Oil Company (KOC). A very deep high-temperature/high pressure (HT/HP) dolomitic formation is at approximately 15, 000 ft (vertical), poses complex completion and producibility challenges. Exhaustive log suite and core analyses confirm some porosity development and gas shows. Unlike the proven carbonates up-hole in the same asset, the deepest dolomite units have extremely low permeability, and may not flow unless enhanced by a natural fissure network and/or hydraulic fracturing.
Only a few wells have been attempted for completion in these deepest dolomite layers, which failed to flow even after matrix acidizing treatments. The effective completion design will require good understanding of formation mechanical properties and fluid leakoff behavior, leading to optimal horizontal wells to maximize reservoir exposure completed with multiple hydraulic fracturing treatments to establish hydrocarbon production at commercially acceptable rates. Therefore, properly designed and effectively executed extensive fracture diagnostic tests are critical in the current pre-appraisal stage. In addition, multiple acid-fracturing treatments have already contributed to the understanding of fracture geometry development and fracture flowback characteristics.
A fracture diagnostics workflow was developed and deployed to appraise the deepest dolomite layers. Critical fracture mechanics data were collected and analyzed. The main fracturing treatments have also yielded crucial results, which will help the design team in optimizing the horizontal well completions. This comprehensive workflow can be successfully applied in characterizing challenging formations elsewhere where the well and regional data are limited in the appraisal of similar light oil/tight gas-bearing unconventional carbonates.
Fidan, Erkan (Kuwait Oil ) | Darous, Christophe (Schlumberger) | Bloushi, Taha (Kuwait Oil) | Pradhan, San P. (Kuwait Oil) | Singh, J.R. (Kuwait Oil ) | Dashti, Qasem M. (Kuwait Oil ) | Al-Mutairi, Mubarak D. (Kuwait Oil )
A comprehensive diagnostic data-fracturing campaign (Fracture Pressure Analysis: FPA) was undertaken by the Gas Fields Development Group (GFDG) of North Kuwait in January-March 2013. The campaign involved executing FPAs on the primary zone of interest (Organic-rich Carbonaceous Shale: OCS) as well as underlying and overlying carbonates to establish “fraccability” and in particular the hydraulic frac vertical containment aspect, which are much needed for the successful planning of an appraisal program.
This paper summarizes the resuts of those FPA tests and how the acquired data is used to calibrate the wellbore geomechanical model. This initial FPA campaign is the onset of a more comprehensive evaluation program planned for 2013 onwards. FPA sequences were executed on the OCS, underlying and overlying formations with encouraging results. The main concern was whether the OCS would yield hydraulic fracture (fracture initiation) below surface treatment pressure limitation of 13,500 psi (Maximum allowable surface pressure). The fracture initiation was successfully established in all three zones. In addition, multiple “fracture re-opening tests” were performed to evaluate the ranges of the fracture closure stresses during the leak-off. Multiple down-hole memory gauges were utilized to ensure elimination of wellbore effects on treatment pressure. KCl-laden incompressible water-based fluid system enhanced with friction reducer was utilized in all three stages to ensure minimal friction loss and damage. This formation suite has very complex mineralogical attributes as it is a mixture of clastics, carbonates and hydrocarbons, with reservoirs that can be very tight (possibly at micro-Darcy).
This campaign will lead to an optimal selection among the vertical completion options (hydro-fracturing design), and will help to successfully plan for horizontal well completions.
Pradhan, San Prasad (Kuwait Oil Company) | Acharya, Mihira Narayan (Kuwait Oil Company) | Fidan, Erkan (Kuwait Oil Company) | Rao, Narhari Srinivasa (Kuwait Oil Company) | Al-Awadhi, Mansour (Kuwait Oil Company) | Singh, J.R. (Kuwait Oil Company) | Dashti, Qasem M. (Kuwait Oil Company)
Deep HP-HT sour carbonate reservoirs in Northern Kuwait have varied matrix properties and fracture intensities. The wells are drilled with barite laden OBM with 1,000-2,000 psi overbalance. The intervals suffer substantial formation damage during drilling as is evident from the fact that the wells normally do not get activated, in spite of creating an underbalance of 5,000-6,000 psi by displacing mud with a lighter fluid.
During the early exploration phase of these reservoirs, long and/or multiple intervals were perforated and treated with conventional matrix stimulation using 28% retarded/ emulsified acid in stages with chemical diverter (gel based and visco-elastic surfactant based). Post stimulation PLT survey in these wells indicated, that only about 5-10% of the total perforated interval contributed to the production; concluding that the diverters were found to be ineffective leading to sub-optimal reservoir management due to poor zonal contribution.
As part of strategic reservoir management process selective bottom up approach in perforation with higher concentrations of HCl treatment and without diverter has been adopted in these reservoirs. To obtain a degree of diversion over the perforated interval, the acid was pumped at higher rate and with higher pressure. Adoption of this changed perforation and stimulation treatment has been proved to be the key enablers for improving zonal productivity.
Around 30 wells have been completed with this changed perforation strategy and treated with this new recipe and technique. Post stimulation test results are comparable to those wells treated with regular matrix stimulation. The PLT survey post acid wash treatment by this technique showed that zonal contribution has improved. This process in addition to being simpler is faster and cost effective. This paper presents the comparison between the two types of perforation and stimulation strategies vis-à-vis test results and also the QA/QC followed prior to pumping the acid.
Tight gas, low-permeability reservoirs offer a tremendous challenge withrespect to effectively completing and draining a target reservoir.Openhole-packer completions in horizontal wells offer a cost-efficient means ofaccessing the entire lateral section, assuming the target pay can beeffectively stimulated. The challenge with openhole completions compared withmore-conventional cased, cemented, and limited-entry perforated completions isunderstanding and controlling hydraulic-fracture geometry--specifically, thenumber and location of fracture-initiation points and the fracturing-fluid flowinto the near-wellbore (NWB) region of the reservoir. Fiber-optic-baseddistributed temperature sensing (DTS) offers a method for identifying,quantifying, and evaluating the NWB fracture geometry, the fracturing-fluiddistribution in these broad openhole sections, and overall stimulationeffectiveness. DTS can also reveal success or issues with respect to effectivezonal isolation when using mechanical isolation during the hydraulic-fracturingprocess. In this particular case study, a lateral well in a basin centered gasarea was completed with swell-packer interval isolation by use of fracturesleeves for reservoir access. By coupling fracture-treatment responses andopenhole log characteristics with the NWB DTS data during pumping and warmback, an integrated assessment of the completion stimulation effectiveness andefficiency was performed. The end result of this assessment provided animproved understanding of the current completion performance and allowedoptimization of openhole completion projects for future wells in this samearea.
In order to make commercial and development decisions effectively and more rapidly, new appraisal and testing technologies are needed to maximize early data collection and subsequent subsurface understanding as quickly as possible. For Unconventional Gas and Light Tight Oil (UGLTO) projects, some of this critical data can be derived from hydraulic fracture stimulation and inflow profiling activities.
For UGLTO projects, achieving an optimum hydraulic fracture stimulation is a continuous endeavor beginning as early as possible; and balancing the cost of completion vs. production performance is critical as the completion/stimulation is a large cost component of the well and heavily influences production rate/ultimate recovery. The fast paced development and introduction of new completion technologies requires diagnostic technology that can help us understand stimulation effectiveness, assess new completion technologies, and evaluate which zones are the most productive.
One emerging technology, fibre optic distributed sensing has the potential of providing key insights during both the hydraulic fracturing and initial flowback. The passive nature of fibre optic sensors allows intervention-free surveillance, which makes fibre-optic technology an effective platform for permanent sensing in producing wells. Until recently, the oil & gas industry fibre optic sensing technology has focused mainly on temperature (DTS) profiling along the wellbore. In 2009, it was first demonstrated how fibre optic distributed acoustic sensing (DAS) can also be used for downhole applications. Where hydraulic fracture diagnostics based on DTS alone in the past sometimes yielded ambiguous results, the combination of both acoustic and temperature sensing provides a step-change improvement in the ability to perform real-time and post-job diagnostics & analyses of the stimulation.
The different horizontal well case studies presented in this paper will illustrate how the combination of DTS and DAS has the potential to enhance the monitoring, assessment, and optimization of openhole and limited entry designed hydraulic fracture stimulation treatments.