Al-Murayri, M. T. (Kuwait Oil Company) | Al-Mayyan, H. E. (Kuwait Oil Company) | Moudi, Kamal (Kuwait Oil Company) | Al-Ajmi, F. (Kuwait Oil Company) | Pitts, D. (Inc.) | Wyatt, M. J. (Inc.) | French, K. (Inc.) | Surtek, J (Inc.) | Dean, E. (Colorado School of Mines)
Chemical EOR (CEOR) can be economic in a low-price environment, but it requires economic insights be integrated into the initial reservoir screening, laboratory and numerical simulation evaluations, and continued review through field implementation. The CEOR economic evaluation for the Sabriyah Lower Burgan (SALB) using this integrated process found that surfactant-polymer and alkaline-surfactant-polymer flood had different economic potentials due to different oil recoveries, facility costs, and operating costs. Initial reservoir screening of the SLAB indicated that LoSal and CO2, flooding might also have economic potential. Laboratory corefloods injecting field proportioned volumes of chemical solutions using dead oil and reservoir rock resulted in chemical cost average $3.12 per incremental barrel of oil for alkaline-surfactant-polymer formulations and $18.61 for surfactant-polymer formulations. Live oil corefloods for corresponding chemical formulations cost per incremental barrel estimates were $3.70 and $7.83. LoSal process provided no incremental oil based on laboratory coreflood results. Numerical simulation forecast economics included chemical costs, estimated operating costs, facilities cost, drilling of wells, and other capital costs. 2.2, 5.4, and 60 MMbbl pilots forecast by numerical simulation indicated that alkaline-surfactant-polymer cost per incremental barrel of oil was $28.63, $10.42, and $10.95 for the respective pilot sizes. Smaller pilots show a greater impact of fixed costs such a facilities and new wells. 5.4 and 60 MMbbl pilots paid out at 3.4 years or less. Corresponding discounted rates of return were up to 14%. Sensitivity analysis indicated that crude oil price has the greatest effect on chemical enhanced oil recovery economics, regardless of pilot size. This paper summarizes how economic applications at each phase of a chemical flood evaluation are performed and how those evaluations can be understood and applied to prevent adverse project selection. Economic parameters should be evaluated at various phases of project evaluation, influencing decisions to move forward. Methods of evaluation at each phase are documented and discussed using the Sabriyah, Lower Burgan study as a basis.
North Kuwait has vision to increase oil production from its major reservoir and it is planned to be achieved by covering the major reservoirs under the umbrella of enhanced oil recovery (EOR). Sabiriyah Lower Burgan (SALB) is the biggest sandstone reservoir in Sabiriyah field with high permeability and strong aquifer support. Paper describes steps planned from present development strategy of simply infill drilling to EOR to improve the production scenario in future.
Primary recovery from reservoirs like SALB are expected to be good. Performance of the reservoir especially rise in water cut of SALB was analyzed which suggested that though primary recovery would be good but will take longer time to achieve. EOR screening was performed and suitable EOR methods were evaluated using mechanistic model. Screening considered target oil, water quality, permeability, oil viscosity, temperature, aquifer and injection capacity. Lab experiments were performed for the identified EOR processes and most suitable method was selected. EOR pilot area and pilot design performed to take it forward from concept stage towards reality.
SALB Layered part is an acceptable candidate for EOR process due to favorable mobility ratio which reduces the need for mobility control agents, reservoir being mixed wet system which is encouraging for improving unit displacement efficiency and reservoir rock properties are conducive to most forms of EOR. Low salinity water, CO2, N2 and Chemical EOR methods were evaluated. Mechanistic model based Estimated Recovery factor range for these EOR methods indicated Chemical EOR, (A) SP as most effective EOR method. Lab experiments were performed for CO2, N2 and ASP. In Lab, miscible N2 flooding was not found feasible whereas CO2 flooding was feasible for either as CO2 or a blend of CO2/NGL. Coreflood experiments suggested surfactant-polymer or alkaline-surfactant-polymer pilot flood as promising EOR methods for SALB. KOC has planned to proceed with Chemical EOR with its further evaluation through single well chemical tracer test (SWCTT) as first step. A multi-well pilot was also recommended assuming a successful single wells tracer test which would provide a better understanding of chemical solution injectivity, oil recovery potential, chemical retention by the reservoir, effect of the water drive on alkaline-surfactant-polymer flood potential and operational issues. Target layer and likely area was identified for EOR pilot.
EOR in a reservoir with strong aquifer drive has its own challenges but merits of SALB for enhancement of recovery are encouraging. The paper provides an insight of applicability of Chemical EOR in a large reservoir with strong aquifer that will pave the way for similar reservoirs in Kuwait and worldwide.
Sabiriyah Mauddud, has been on water flood since Dec 2000 with seawater. Reservoir souring is the in-situ generation of H2S in the reservoir itself due to waterflood operations using seawater. Traditionally, Mauddud is a sweet reservoir & some degree of reservoir souring occurs due to Sulfate-Reducing Bacterial (SRB) activity. As a new initiative for tracking souring, H2S coupons were used for the first time in Kuwait at one of the EOR wells in open hole condition during drilling. This has been extended to flowing wells as part of the FBHP survey so that the coupons reflect H2S levels nearest to Mauddud perforations, using the slick line, for the first time in the industry, to detect micro H2S levels.
Different methods are used to measure H2S concentrations such as WH samples or titration / dragger tubes from needle valve (separator unit) for surface sampling, or taking bottom hole sample using conventional sampling chamber which is usually made from stainless steel material, normally reactive with H2S.
It is a challenge to accurately measure low ppm levels of H2S in formation fluids where there is a risk of not capturing these concentrations using conventional samplers/ sample bottles because of the reaction between H2S and sample chamber during bottom hole sampling operation. Therefore, non-reactive coated sampling bottles were recommended and used in the past. The option of H2S coupons to be used as slick line operation is one of the key improvements in tracking H2S without loss of tiny content of H2S via adsorption in wellbore/ flowline transit.
With H2S coupons, certain metal alloys discolor, as a result of corrosion, only due H2S. These alloys are said to be "Specific" to the presence of H2S. Discoloration due to H2S is weakly dependent on temperature and exposure time. Discoloration results in loss of the original shiny or glossy finish. This phenomenon is largely a function of partial pressure, not concentration. This is true for both gas phase and liquid phase. Hence, the H2S coupons measures the total H2S for the reservoir fluid.
SA-X is a vertical well in Sabiriyah Mauddud equipped with Y-Tool. H2S coupons were run to detect H2S levels across Mauddud. Two sets of H2S coupons were placed inside the bottom of the tool along with pressure and temperature sensors. Consistent results were obtained from both H2S coupons sets. Only the high sensitive coupon was affected indicating H2S partial pressure higher than 0.005 but less than 0.018. H2S level is found in the range between 5 – 15 ppm which is quite close to what has been measured in the lab during compositional analysis during PVT studies for monophasic fluid. This has built team's confidence regarding the validity of the data via souring coupons. This procedure has now become part & parcel of our routine surveillance activities for tracking reservoir souring.
The procedure has added a simple but accurate fit-to-purpose tool for tracking reservoir souring in North Kuwait.
Alkhaldy, Meshal (Kuwait Oil Company) | Alsaadi, Dhari (Kuwait Oil Company) | Al-Shuaibi, Nawaf (Kuwait Oil Company) | Al-Saffar, Maytham (Kuwait Oil Company) | Elafify, Ibrahim (Kuwait Oil Company) | Alkubaish, Yasser (Schlumberger) | Moustafa, Shady (Schlumberger) | Mobasher, Mohamed (Schlumberger) | Dalali, Hamad Al (Schlumberger) | Saleh, Rashad (Schlumberger) | Keot, Chandan Jyoti (Schlumberger) | Jokhi, Ayomarz Homi (Schlumberger) | Hasan, Said (Schlumberger)
The objective is to increase the production/injection rate of the existing old sick vertical wells that are completed with 7" casing, by extending the reservoir exposure with converting those wells to horizontal producer/injector.
In the initial Field Development stage, many wells were drilled and completed with 7" casing up to the surface. Several of those old wells are lying inactive in North Kuwait which has one of the largest oil reservoirs in the country. In addition, of the limited surface locations in the field combined with the growing anti-collision challenges, feasibility studies were carried out for reviving such sick wells which can't be delivered via limited hole sections; accordingly, an innovative idea introduced to complete those wells with 3 7/8" or 4 1/8" Open Hole Completion. To address the required challenges, 2-7/8" PAC HT DP had been used along with 3 1/8" Motor.
Consequently, DP had to be spaced out every trip to maximize the WOB transfer and mitigate Buckling issues.
This paper provides an overview of 3 7/8" slim horizontal hole by taking the challenge to the next level by drilling the longest 3 7/8" horizontal slim hole in the world with a total footage of 4,565 ft. Total 7-runs had been performed to achieve this lateral length due to the limitation of BHA/LWD Battery life. Thirteen such wells have already been drilled consisting of 7 Injectors and 6 Producers. The Slim Wells are completed as an Injector with 5" seal assembly along with 4 ½" Tubing, or as a Producer with 3 ½" tubing and ESP. All wells (both Injectors and Producers) have yielded results commensurate to the potential of any new conventional horizontal well. Consequently, Slim Hole Horizontal wells were successfully drilled in Kuwait Oil Company fields. As such, the campaign of reviving the sick wells helped KOC to achieve higher return on investment in mature assets through minimizing top hole construction cost and time. The success has opened up new avenues for KOC.
Re-entry wells helped to achieve higher return on investment in mature assets through minimizing top hole construction cost and have been drilled at 1/3rd the cost of a new well. It also accelerates time to oil production from existing wells and has minimized the prevailing location constraints. KOC has launched an aggressive plan to complete more such sick wells.
NKJG area comprises of eight fields that are structurally complexcharacterized by high pressure & high temperature (HPHT) reservoir properties, critical or near critical nature of the reservoir fluids, high concentration of H2S & CO2 and multiple zones consisting of variations in carbonate formations. Tectonics, as well as the depositional complexities further complicate the trapping and distribution of hydrocarbons, leading the commingled completion and production challenges. Sabriyah field is the second prolific field in NKJG and is divided primarily into two parts; crestal part which is highly fractured and platform part is matrix dominated. Water breakthrough is observed in some of the wells located in the crestal part, and in general, two types of fluids are encountered (gas condensate & volatile oil).
The pilot well where the new diversion technology was implemented is located in the western flank of the Sabriyah field. Limited natural fracturing occur across the 268 ft perforationinterval which is too long for effective stimulation in a conventional "bullheading" approach. Although the permeability is low, vertical permeability distribution ranges widelyacrossthe perforation interval (0.001- 10 mD). Nodal Analysis showed the possibility of tripling the production if all the perforation intervals were stimulated efficiently and contribute to flow. As a result, a sequence of operation was planned which included re-perforation of the current interval followed by stimulation to enhance well performance.
Due to the operational complications, re-perforation was not completed as planned and the well was killed twice with heavy mud causing further damage. As a result, severe formation damage was created leading to significant loss of production, necessitating a robust stimulation treatment. An innovative "High Rate Matrix Acidizing (HRMA)"technique was designed to restore and enhance well production; where a Step Rate Test (SRT) was done prior to injecting main acid treatment to avoid unintended fracturing. In addition, different diversion strategies were usedin combination: one to divert across perforations and the other to divert stimulation inside the formation. All the chemical fluids that used in the HRMA was tested in the lab to confirm its compatibility and solubility with reservoirrock and fluid.
Production was successfully improved after HRMA; where the wellhead pressure, oil and gas rate increased substantially as confirmed by the nodal analysis. During stimulation, there was clear indication of diversion with change in pressure, which confirmed the efficiency of the diverters, and possibility of treating all perforation intervals. Based on the success of this HRMA treatment, similar approach will be used to stimulate other low performers in the North Kuwait Jurassic Gas (NKJG)asset. This paper will provide the details of design, well results, and the overall learnings to address one of the key stimulation challenges in long-perforated deep HPHT wells of NKJG.
Nelson, David Jesudian (KOC) | El-Din, Hossam (KOC) | Nair, Sajan (KOC) | Mohammad, Hasan Ahmad (KOC) | Juyal, Mukul (Schlumberger) | Wenang, Martine (Schlumberger) | Keot, Chandan Jyoti (Schlumberger) | Osman, Salih Noreldin (Schlumberger) | Mohammed, Abeer Ahmed (Schlumberger) | El-Derini, Khaled Mohamed (Schlumberger)
Mauddud reservoir in Sabriyah field is a giant heterogeneous carbonate reservoir discovered in 1950s. The field is on production since 1957 with natural depletion since it has no aquifer support. Overtime, with continuous production there has been a decline in reservoir pressure which affected the field productivity. This paper presents successful field development strategies on multi-discipline approach, integrating sub-surface domains through comprehensive planning studies and high end geo-steering technologies with objective to arrest the pressure decline and sustain oil productivity from the Sabriyah Mauddud giant carbonate reservoir.
For optimum exploitation of giant Sabriyah Mauddud reservoir, KOC is currently performing high volume producer and injector horizontal wells drilling campaign. Meticulous predrill planning integrated with advance geo-steering technologies such as Multiple Bed Mapping Distance to Boundary (DTB), Azimuthal Density and Ultra High Resolution Resistivity Image helped KOC to get best results from horizontal wells, not only in short term, but more importantly long term. An effective horizontal well would minimize amount of attic oil, delay water production and hence increase ultimate reservoir recovery. To reduce overall well cost, minimize well bore instability and maximize well production, a very innovative strategy was adopted to drill medium radius 8.5" curve sections with high dog leg severity using special drilling technologies. The Mauddud reservoir varies in property and thickness in different segments of the field, therefore tailored-to-fit drainholes strategies were adopted to exploit the massive Sabriyah carbonate reservoir efficiently.
The new strategy of high dog leg medium radius ensured footage reduction by almost 50% in build section. Lower inclination through top shale sections ensured better wellbore stability and smoother drainhole. Reduction in footage meant the curve sections were drilled in less than 48 hours in a single run and resulted in huge cost savings. Another major achievement of this strategy was that landing point was positioned closer to mother bore (for sidetrack) because of reduced horizontal displacement by approx. 60%. After implementing drainhole strategies tailored to address unique challenges of particular segment of the field, horizontal producer and injector wells were successfully placed on top and bottom part respectively of Mauddud reservoir with desired exposure length, resulting in maximum reservoir contact and minimize water coning. An overall improvement of 30% in production rate and maintained water cut rate recorded on applied horizontal well case studies compared to non-horizontal wells. Consistent application on these field development strategies would be beneficial in long term by achieving increase of ultimate field recovery.
This paper provides insight on successful application of innovative field development strategies to optimize production from Sabriyah Mauddud reservoir. Field specific development plans along with innovative landing strategy and proactive geo-steering with multi boundary mapping along with high resolution resistivity imaging tools minimize geological risk and helped to achieve horizontal well and field development plan objectives. Similar approach can be adopted to sustain long term oil productivity from this type of complex carbonate reservoir.
Al-Othman, M. R. (Kuwait Oil Company) | Elmofti, M. (Halliburton) | Bu Hamad, A. (Kuwait Oil Company) | Alhouti, N. B. (Kuwait Oil Company) | Al-Haddad, M. N. (Kuwait Oil Company) | Al Hamad, A. M. (Halliburton) | Allam, A. (Halliburton) | Eid, W. (Halliburton)
Numerous methods have been applied in matrix acidizing over the previous decades to successfully stimulate multiple zones. These methods have also been implemented in fracture acidizing with varying degrees of success. This paper discusses the application of a new biodegradable material used for diversion in multiple zones or long formation intervals and presents improved results obtained using a new biodegradable diverter.
Acid-fracturing diversion can be more challenging than diversion for matrix acidizing. To effectively stimulate multiple or large zones, the diversion treatment should be able to bridge not only the perforations themselves, but often inside the fracture system as well. This can be difficult because acid reacts with the rock, forming an etched/enlarged path, thus the diversion also requires bridging inside this conductive path. This differs from matrix acidizing techniques, in which the diversion depends mostly on the perforations in an interval(s) and the stimulated reservoir permeability. Historically, several methods have been implemented for acid-fracturing diversion, such as ball sealers, viscous fluids, packers, etc., resulting in limited success or cost-ineffective results. The new biodegradable material helps improve acid fracturing diversion success in multiple zones or long formation intervals.
The development of this biodegradable material is discussed along with a case study. Also, details are provided of the biodegradable material evaluation that consists of 1) pre and post-temperature logs, 2) pre and post-injection logging profiles, 3) pre and post-production history, and 4) further recommendations. The results of the evaluation methods show that the biodegradable material can be used as an effective alternative diversion method to seal existing perforations and effectively stimulate all perforated intervals. Production increased more than threefold, and the targeted fracture height was achieved based on the temperature log data.
Al-Qenaie, A. (Kuwait Oil Company) | Chetri, H. B. (Kuwait Oil Company) | Tiwari, S. (Kuwait Oil Company) | Al-Twaitan, T. M. (Kuwait Oil Company) | Abdullah, M. B. (Kuwait Oil Company) | Ranjan, P. (Kuwait Oil Company) | Aslanyan, I. (TGT Oil & Gas Services) | Prosvirkin, S. (TGT Oil & Gas Services)
Successful EOR project management in mature fields depends on proactive planning that includes reservoir characterization and determination of the engineering design parameters. Base-Line logging performed in the pilot EOR pattern before implementation of an EOR project will make possible an early detection of any potential problems and weaknesses to avoid costly subsequent repairs or alterations. The objective of this paper is to demonstrate the results and value of Reservoir-Oriented Base-Line Logging carried out in Sabriyah Field, Kuwait, before ASP injection. The Base-Line logging is focused on the flows behind pipe and any anomalies that might have impact on the project.
Seven new vertical wells were drilled in a selected area within an existing waterflood pattern, to monitor the viability of pilot polymer injection in the field. An integrated suite consisting of reservoir evaluation tools, High Precision Temperature (HPT) and Spectral Noise Logging (SNL) tools, and metal losses evaluation tool (EmPulse), were run on slickline under shut-in conditions. Temperature is sensitive to any lateral flows and possible behind-casing cross-flows between permeable zones. Spectral noise logging can distinguish between noises caused by fluid flows through well completion elements and the reservoir. The idea was to record the wellbore and reservoir initial conditions before any mechanical or reservoir effects begin to influence the EOR performance. Analysis of subsequent Time-Lapse logging would be easier with this base-line information on hand.
The five wells were drilled in a 5-spot pattern in the selected area, with two additional logging well and a sampling well for continuous monitoring. The objective was to check for possible communication of the target reservoir with underlying and overlying formations to prevent off-target chemicals injection, and get a baseline for metal thickness of each barrier. At the same time, it was vitally important to trace the cold injection water propagation in the target reservoir before the EOR started.
Sabiriyah Mauddud and Upper Burgan are two of the giant reservoirs in North Kuwait(NK) under active water flood since 2000. About 400 MBWPD of water is currently being injected to maintain the reservoir pressure & improve the production/recovery. A comprehensive workflow process was developed and implemented to understand the waterflood performance, pressure-production response trends and map the opportunities to encash the benefits in terms of quick oil gains. The paper discusses the best practices adopted to increase production from two of the water flooded reservoirs in NK.
Sound workflow process was created by integrating the technical inputs under collaborative environment from subsurface & surface teams. Series of segment reviews are conducted to understand the connectivity between producers & injectors, duly integrating all surveillance data. Analytical diagnostic tools have been used to distinguish between the good water and bad water and improve the VRR & sweep. Live ESP data is monitored and tracked at intelligent field collaboration centre to decide about the actions for the wells requiring ESP upsizing, downsizing and VSD/choke optimization. Wells with running ESPs were identified for VSD & choke optimization, using rationalized technical criteria. Wells with failed ESPs are reviewed for smart replacements with water shut off/ water flood conformance & ESP re-design. Simultaneous actions for the well model creation; running sensitivity and scheduling in the workover rig are taken up.
ESP upsize, along with VSD installation/ choke optimization, was implemented in number of wells with significant oil gain (about 11% enhancement within a short time frame). As a part of the process established, this activity has become a regular practice in NK. Such wells are under constant monitoring so that water injection actions in nearby injectors, if needed, could be taken up such as allowable management, arresting the declining trend etc. The benefit of mega water flood activities have been reaped in terms of production enhancement adhering to the best reservoir management practices.
Quick understanding of the Water flood response and relignment of actions on the associated wells via rigless and rig workovers is the key to the success for significant ramp of the NK production within a short time window of 6-7 months. Several work flow processes established during the campaign are now deeply imbeded within NK asset.
The combination of horizontal wells and multistage fracturing enabled the development of tight carbonate reservoirs. The successful completion of these reservoirs can be challenging. Correct placement of multistage intervals plays a critical role in improving and sustaining production. Openhole (OH) multistage (MS) technologies enhances reservoir contact and productivity by optimizing the distribution of the stages across the openhole. This paper presents an engineering technique to optimize OH fracture stages and cluster placement distribution within heterogeneous unconventional oil carbonate reservoirs based on formation, completion properties, and reservoir fluid distribution.
Completion technology is based on distributing intelligent packers along the lateral section to develop the MS fracturing stages. Intelligent packer displacement influences fracture effectiveness and conductivity. Equal spacing packer placement can undermine formation potential and productivity results. The placement of the packers and their ports is based on the petrophysical and mechanical properties of the formation to increase the cumulative production in a shorter timeframe and to help improve recovery. The method followed is based on an analysis of the reservoir properties (porosity and permeability). These were later integrated with the measured rock mechanical properties. The developed integrated model was used to categorize the rock into segments that share similar properties.
The use of an advanced azimuthal sonic tool with a high signal-to-noise ratio and wider frequency response helped to improve the accuracy in assessing formation mechanical properties. In addition, conventional logs, when combined with formation mobility measurements, help to calibrate the permeability model and classify the formation into distinctive clusters. These clusters are then grouped according to their mechanical and brittleness properties to form a separate unit with a selected fracture port to help ensure the necessary fracture length. The developed method provides an opportunity to determine the necessary fracture stages and to reduce the risks of overor underplacement. It also improves stage integrity, helps to ensure better distribution of the acid across the formation matrix, and provides effective propagation of the fracture network.
The applied procedure follows an innovative approach to optimize the fracture stage and cluster placement distribution across the reservoir using a new combination of advanced and conventional data acquisition and interpretation. The case study presented in this paper demonstrates the benefits of engineered fracturing stage placement, as compared to a geometric displacement.