Presence of H2S detected in producing wells of North Kuwait sweet waterflooded reservoirs over the last 18 years, gave indications of biogenic souring. In response to this, the Kuwait Oil Company engaged in detailed souring potential assessments of selected reservoirs such as the Raudhatain Mauddud (RAMA), to predict the further generation of H2S and define the required souring mitigation strategy to ensure safe production over the remaining field life.
The souring simulation modelling was conducted on the RAMA subsurface model with support from Shell, using a state of the art souring prediction program. The initial phase of the study consisted in the history match simulation to define the most likely souring mechanism in the field. The forecast considered various scenarios with a range of sensitivities on carbon nutrient and sulphate levels, both in formation and injected water in the field.
The history match simulation results showed a good correlation with most of the producers with available H2S data. The Forecast simulation over the next 15-year period predicts a moderate souring severity for this reservoir, based on the maximum H2S mass flow rate of 90 kg/d and H2S in gas maximum concentration of 85 ppmv at the field level.
This work provides the petroleum Industry further insights into the souring behavior when effluent water is injected in addition to seawater, particularly the effects of additional carbon nutrients fed into the reservoir.
Gorgi, Sam (Halliburton) | Joya, Jose Francisco (Halliburton) | Al-Ebrahim, Ahmed (Kuwait Oil Company) | Rashed Al-Othman, Mohamad (Kuwait Oil Company) | Abdullah Al-Dousari, Mohamad (Kuwait Oil Company) | Mohamad Ahmed, Abdulsamad (Kuwait Oil Company) | Omar Hassan, Mohamad (Kuwait Oil Company) | Mohammad Al-Mansour, Jassim (Kuwait Oil Company) | Elsayed, Abdou (Kuwait Oil Company) | Alboueshi, Alaa Eldin (Halliburton) | Allam, Ahmed (Halliburton) | Robles, Fernando (Halliburton)
This paper presents a case history application of real-time fiber-optic technology in the Bahrah oil field, onshore Kuwait. A primary challenge during openhole swellable packer completion operations with multistage fracturing is understanding the number of fractures induced in the formation, particularly in heterogeneous formations where the fracture pressure energy will be distributed along the openhole section. Therefore, fiber-optic technology was selected for the Bahrah project. The application consists in diagnosing a tight carbonate reservoir after multistage acid fracturing and milling the baffles of a production sleeve completion to obtain a well production profile. This technology consists of a fiber-optic cable and a modular sensing bottomhole assembly (BHA). The fiber-optic cable provides distributed temperature sensing (DTS), whereas the BHA is used to monitor pressure, temperature, and the casing collar locator (CCL) in real time.
The usual procedure when using conventional coiled tubing (CT) to stimulate a carbonate openhole section is to treat all pay zones with acid and diverter, which increases both operation time and operational costs. In addition, inadequate control of the treatment placement will often result in ineffective stimulation. When using the fiber-optic technology, monitoring is performed by analyzing the distributed temperature profiles both before and after stimulation; the BHA helps ensure that the optimum pressure is maintained and that the fluid is placed accurately through depth correlation sensors. All components of this intervention are performed in a single trip, which reduces both costs and operation time.
This paper presents an application that uses the modular sensing BHA to improve the performance of milling balls and baffles in the horizontal production sleeve completion. Afterward, DTS is used to diagnose the reservoir performance after multistage acid fracturing to identify fracture initiation points (FIPs). This assists in design optimization, provides better understanding of formation properties, and helps determine the flow rate distribution of each stage across the entire lateral. Another application uses DTS to obtain the production profile of a 3,286-ft horizontal section while flowing back the well through an electrical submersible pump (ESP). The paper presents the methodology and results of these applications.
Using this technology in the petroleum industry helps reduce operation time by up to 50% as a result of performing various CT activities in a single run. This eliminates the need for additional logging or slickline runs using the same BHA, after performing the milling operation to collect DTS data for FIPs and flow rate distribution analysis in the same run. It also reduces costs by enabling real-time decision-making capabilities and effective stimulation.
Waterflood (WF) is the main drive mechanism of North Kuwait reservoirs. Different development strategies has been adopted to develop a giant carbonate reservoir in the asset. Irregular scheme of WF has been implemented in the last 5 years which made it challenging to properly evaluate the WF performance. This paper presents both numerical and analytical approaches to assess the current performance of the waterflood in this reservoir.
The first method uses actual production and injection data to generate traditional waterflood plots such WOR vs. Np, injection throughput, VRR and other diagnostics.
The second approach uses the numerical model to understand the fluid movements in terms of production and water injection. A high resolution model is used to know about the horizontal producers and injectors WF scheme. Streamline model tool is used to understand how the injectors impact their surrounding producers. Injector's efficiency, allocation factors and reservoir sweep efficiency are calculated using the simulation model.
Both approaches are compared to have a better evaluation of the waterflood.
When the waterflood started, a regular i-9 spot patterns was the way to develop the reservoir. The heterogeneity of the reservoir was observed clearly in the different performance of each pattern. Also, high permeability layer (thief zone) has adversely affected the reservoir performance during WF.
The sharp increase of water cut with very low corresponding recovery factor triggered a paradigm shift in developing this waterflooded reservoir. Injecting in lower layers and producing in upper layers (horizontal wells) was the next stage. This brought a great challenge to assess the performance of this WF scheme. Evaluating such a development strategy remains a achallenge.
KOC has been producing oil using dual completions from different pressure regime zones from the same well and South East Kuwait field has many such dual completions wells which are currently being converted from natural flow completion to artificial lift completions. In one of such dual completion naturally producing well, first time in world an artificial lift system - Anchor Pump was installed in Short String (SS) through rigless intervention. Thus project well had un conventional dual completion in the field first of its kind i.e. Sucker Rod Pump (SRP) installed in short string and natural producer through Long String(LS). The well produced for some time through both strings and an intervention by workover rig was required due to high water cut and stuck anchor pump in short string. The paper describes the challenges and initiatives and learnings for safe execution of unconventional dual completion well workover.
Due to combination of natural flow and SRP artificial lift completion, the X-mas tree configuration and associated surface equipment of such well was had several constraints and HSE issues for mobilization of rig and dual production zones with varying pressure regimes have challenges of initial well killing due to plugged short string by stuck anchor pump. The risks were identified during planning stage and risk reduction measures were jointly agreed with Field Development. Various options were explored to minimize risks to ALARP level and subsequently addressed in Work Over Program. The surface equipment constraints were eliminated through rigless works and X-tree configuration were modified to suit deployment of a workover rig. Well process safety principles were applied to accomplish initial well killing in both production zones so as to safely pull out existing dual string completion without any well control issues. An initiative to use sucker rod back off tool, first time and safe back off operation was performed successfully from very close to stuck point.
The existing completion strings were pulled out and further well cleanout and workover program was well cleanout Finally, well was completed with new ESP completion string and successfully production tested. The most important factor in success was proactive planning keeping in view of Process Safety for well control issues and effective communication among the concerned parties.
The initiatives adopted in execution of such a challenging well intervention resulted enhancement in safety to rig crew and Rig operational safety standards in addition to contribution towards cost reduction. Lessons learnt has potential of rig time saving specially during workover of large number of heavy oil wells where stuck sucker rod conditions are very common due to sand invasion in tubing during production.
A few horizontal wells were drilled in Kuwait, heavy oil field, as a part of cold production testing. Various workover interventions were performed on these wells. However, some of the wells showed sharp production decline and were producing below expectations. It was suspected that formation damage may have occurred in these ultra-low reservoir pressure wellbores due to the overbalance of the fluids used during interventions.
Concentric coiled tubing (CCT) technology comprising of a downhole jet pump, was recently employed for the first time in Kuwait and was determined to be an effective method to clean the horizontal sections and investigate the reasons for the production problems. The single phase cleanout fluid is circulated down the inner string to power the jet pump, creating a localized drawdown that vacuums the formation solids or fluids out of the wellbore and the combined sand/fluid stream returns via the CCT annulus. The multiple operating modes provided the benefit of cleaning and treating the wellbore in the same run.
This specialized system was successfully utilized to remove sand, evaluate the formation damage and enhance production; meeting all objectives in a single well intervention. Pressure and temperature gauges run below the tool on two wells recorded bottomhole pressure of only 150 psi. Post-production results has pushed the boundaries of the well interventions in heavy oil field in Kuwait and has unlocked several wellbore cleanout and formation damage evaluation opportunities using the CCT technology.
This paper reviews the benefits of the concentric coiled tubing technology and provides a comprehensive case study of the first three horizontal wells. The analysis of the sand and fluid influx profiles obtained during the vacuuming process assisted in to evaluating well production provided crucial data in formulating a management strategy.
Al-Mohailan, Mohannad (Kuwait Oil Company) | Nellayappan, Karthikeyan (Kuwait Oil Company) | Patil, Dipak (Kuwait Oil Company) | Al-Qadhi, Fahad (Kuwait Oil Company) | Sounderajjan, Mahesh (Kuwait Oil Company) | Kunchur, Basavaraj (Napesco Cementing) | Hussain, Khaddar (Napesco Cementing)
In deep wells in Kuwait, completions are fairly standardized which after flow testing are handed over to assets. In course of time, well interventions were done due to one or more of the following reasons - water shut off, addition of zone, plugged perforations, tubing check or production logging. In course of these Rigless interventions over a period of two decades wells have accumulated with fish primarily coiled tubing or wire line fish with some wells being partially plugged. In view of this, a snubbing unit with targeted capabilities to fish inside tubing was deployed.
Earlier, the well could not be killed either by bull heading or with heavy mud circulated by coiled tubing. Thus, the well was identified as a candidate to mobilize a snubbing unit to clean out and place a cement plug. The Snubbing operations itself was being performed for the first time under a regular contract.
The operations include a complete cleaning of all the bridges suspected from about 4200 ft to the deepest depth possible as per the availability of the work string tubulars. It was identified from previous records, this is likely to be an off bottom kill with mud and may not effectively prevent the gas seepage. Thus a detailed planning for a critical cement plug to be placed inside the liner to isolate the open hole from below was made.
Extensive laboratory testing and job modeling was conducted to ensure proper placement of the cement slurry in a challenging HP/HT environment. A 16.5 ppg Gas Block Slurry with low Fluid Loss and favorable rheological propertieswas utilized. Additionally, an alternative, customized engineered designed spacer was used to prevent the formation of a filter cake.
The cement plug was placed with only 1.5″ ID workstring in a 5″ liner while taking due care to prevent cement back into the 31/2″ completion tubing above. Besides, care had to be taken to factor in a sufficiently long thickening time to enable pull out work string safely. The well was successfully secured and isolated and will now allow the utilization of a work over rig to recomplete the well.
The use of a Snubbing Unit has been proven effective to isolate the gas zone and ensure zero pressure on surface to enable mobilization of Workover rig. The paper discusses the challenges in design, planning and operations of placing a 8 bbl plug to stem the gas which made the well unapproachable for the last 3 years.
In 2010, a deep well in North Kuwait was facing continuous complications with gas cuts during completion operations. In order to secure the objectives of the well the open hole section was cemented and was stimulated in LM zone with no success in flow at surface. Additionally, heavy mud was pumped to control the gas influx, resulting in barite settlement but the well reflected pressure of 4000 psi. In order to subdue, attempts have been made to kill the well with CT and heavy mud which failed as CT could not be run to the deepest depth due to high circulating pressures.
Al-shammari, Baraa Sayyar (Kuwait Oil Company) | Rane, Nitin (Kuwait Oil Company) | Ali, Shareefa Mulla (Kuwait Oil Company) | Sultan, Aala Ahmad (Kuwait Oil Company) | Al Sabea, Salem Hamad (Kuwait Oil Company) | Al-naqi, Meqdad (Kuwait Oil Company) | Pandey, Mukul (Weatherford) | Solaeche, Fernando Ledesma (Weatherford)
The Kuwait Integrated Digital Field project for Gathering-Center 01 (KwIDF GC-01) at Burgan Field acquires real-time data from wells and processing facilities as input for its production-surveillance program. Live data from the field is fed into an integrated production model for analyzing and optimizing pump performance. An automated workflow process generates alarms for critical well and facility parameters to identify wells with potential scaling issues. KwIDF workflows are integrated with updated well models to visualize the effect of scale build up on the wellhead performance and thereby assist in quantifying the associated production losses caused by scale deposition. A sensitivity analysis is also performed to identify current and optimal pump operating conditions and prioritize scale cleaning jobs.
The exception-based surveillance of key real-time parameters for wells utilizing electrical submersible pumps (ESPs) in Burgan field has significantly improved diagnostics of scale deposition at wellhead chokes and flowlines. Automated workflows calibrate an integrated production model in real-time, which enables engineers to run a quick analysis of current pump operating conditions and make a proactive plan of action. The application of real-time data and automated models has aided the operator's production team in making informed and timely decisions that enable them to run pumps at optimal operating conditions, with the result that they are able to sustain well production at target levels.
This paper describes an innovative approach to applying real-time data and integrated models in an automated workflow process for enhancing capabilities to diagnose scale deposition in the surface flow network. Examples are presented to demonstrate the application of integrated technology for identifying scaling at wellhead chokes and flowlines and prioritizing a scale removal program for optimizing pump performance.
This paper highlights an unconventional approach of using DPDP (Dual Porosity Dual permeability) simulation technique for modelling hydraulic fractures in a full field simulation model during the forecast analysis performed on a tight carbonate reservoir in Kuwait. This was a part of integrated study in which ‘multi-stage hydraulic fracturing’ was recommended as the most optimum stimulation technique in order to enhance the productivity of all the proposed horizontal producers. Importance of DPDP model increases multi-fold when contrast between fracture and matrix permeability is in the order of 10 times or more. In the studied case, as average matrix permeability of the reservoir is in the range of 2-3 mD, this contrast is magnified to the order of 1000-10000 times (considering fracture permeability is in Darcies) which further complements the use of DPDP model.
Three different approaches were tried to model the impact of multi-stage hydraulic fracturing in the full field simulation model; 1) ‘Enhance Well PI’ for all the stimulated wells, 2) ‘Enhance Matrix Permeability’ in the vicinity of all the stimulated wells, hereby referred as SPSP (Single Porosity Single Permeability) approach, and 3) build ‘DPDP Model’ by using upscaled fracture porosity and fracture permeability without changing the matrix properties. First two approaches are very common in the industry but most of the times are not able to capture the real impact of hydraulic fracturing on flow behaviour (bi-linear flow), whereas DPDP model is designed to capture the flow through dual medium. In both SPSP and DPDP approaches permeability anisotropy (increased permeability in the direction perpendicular to horizontal section of the well) in the fractured zone was very well captured and was needed to honour the hydraulic fractures direction. Fracture permeability was calculated using the Poiseuille's law; few sensitivity cases were run to address the associated uncertainty.
Field cumulative oil production and recovery factor were analysed for ‘Enhanced Well PI’ case, SPSP cases and DPDP cases. Field oil cumulative production in DPDP cases is 6% more than SPSP cases and around 10% more than ‘Enhanced Well PI’ case. The hypothesis for the higher recovery in DPDP case with respect to other two cases is that bi-linear flow (fractures are getting filled with the matrix fluid and then feeding to well) is better represented in the DPDP model. Impact in this case is more significant due to the big contrast between matrix and fracture permeability.
Low capacity with high conductivity signature of hydraulic fracture is difficult to model in the SPSP or just by enhancing the well PI. Study clearly demonstrated the benefits of DPDP model for modelling hydraulic fractures over the conventional methods.
Al-Shuaib, Sarah (Kuwait Oil Company) | Al-Bader, Haifa (Kuwait Oil Company) | Al-Salali, Yousef (Kuwait Oil Company) | Abdel hameed, Waleed (Kuwait Oil Company) | Ahmad, Hanan (Kuwait Oil Company) | Al-Dousari, Sarah (Kuwait Oil Company)
Comprehensive and fully-integrated analyses were performed on the first discovery in Zubair formation of lower Cretaceous age at Bahrah field in North Kuwait with objective of assessing HC potential, well performance, reservoir characteristics and verify connectivity between reservoir flow units.
Based on petro-physical evaluation of OHL, bottom-hole samples, and RDT pressure points two flow units within Zubair reservoir were identified. The OHL showed that these two zones are separated by thin shale strikes additionally; the resistivity against the upper zone showed possibility of being water. Therefore, it was decided to test the two reservoir units separately.
Subsequently, after two successful production tests, analyses of well production performance including Nodal Analysis, PVT, RDT and PTA were carried out for both zones in order to assess reserve potential, obtain essential reservoir rock & fluid characteristics and verify vertical connectivity.
Remarkable oil discovery was made in Zubair reservoir of Bahrah field with substantial addition of proven reserves and commercial production potential, which will definitely support achieving the strategic production target. In order to verify long-term production sustainability, Extended Well Testing (EWT) was conducted. The results showed that this reservoir is capable to produce Hydrocarbon in a sustainable manner. Production Performance, PVT, RDT, PTA and Nodal analysis results showed that the two tested zones in Zubair reservoir are interconnected with same fluid characteristics and it can be considered as one reservoir even though the open-hole logs responses showing that they could be different reservoirs.
This paper will present detailed comprehensive engineering and geological analyses of first Zubair oil discovery in Bahrah Field at North Kuwait. All available structural, petrophysical, PVT and production information were used to develop static model by Petrel-RE and subsequently, detailed data acquisition, appraisal drilling and conceptual field development plans have been established.
Bassam, Abdul-Aziz (Kuwait Oil Company) | Al-Besairi, Ghazi (Kuwait Oil Company) | Al-Dahash, Sulaiman (Kuwait Oil Company) | Sierra, Tomas (Weatherford) | Mohamed, Assem (Weatherford) | Heshmat, Kareem (Weatherford)
The demand for digital oil field solutions in artificially lifted wells is higher than ever, especially for wells producing heavy oil with high sand content and gas. A real-time supervisory control and data acquisition solution has been applied in a large-scale thermal pilot for 28 instrumented sucker rod pumping wells in North Kuwait. This paper focuses on the advantages of real-time data acquisition for identifying productionoptimization candidates, improving pump performance, and minimizing down time when using intelligent alarms and an analysis engine. Real-time surveillance provided a huge amount of information to be analyzed and discussed by well surveillance and field development teams to determine required actions based on individual well performance. Controller alarms and intelligent configurable alarms in one screen enabled early detection of unexpected/unwanted well behavior, re-investigating well potential, and taking necessary actions. The challenge was to handle heavy oil, sand, and gas production, maintain all wells at optimum running conditions before and after steam injections, and take into consideration the effect that injections would have on nearby wells. Recording in the database a "tracking item" for each well event enabled review and evaluation of the wells and creation of optimization reports. The daily, 24-hour surveillance of the wells resulted in observing common problems/issues on almost all wells and other individual issues for specific wells.