The need to develop new tools that allow reservoir engineers to optimize reservoir performance is becoming more demanding by the day. One of the most challenging and influential problems facing reservoir engineers is well placement optimization.
The North Kuwait field (NKF) consists of six fields containing four naturally fractured carbonate formations. The reservoirs are composed of relatively tight limestone and dolomite embedded with anhydrate and shale. The fields are divided into isolated compartments based on fault zones and supported by a combination of different fluid compositions, initial pressures, and estimated free-water levels. Due to natural complexity, tightness, and high drilling costs of wells in the NKF, it is very important to identify the sweet spots and the optimum well locations.
This paper presents two intelligent methods that use dynamic numerical simulation model results and static reservoir properties to identify zones with a high-production potential: reservoir opportunity index (ROI) and simulation opportunity index (SOI). The Petrel* E&P software platform was chosen as the integrated platform to implement the workflow. The fit-for-purpose time dependent 2D maps generated by the Petrel platform facilitated the decision-making process used for locating new wells in the dominant flow system and provided immense support for field-development plans.
The difference between the two methods is insignificant because of reservoir tightness, limited interference, and natural uncertainty on compartmentalization. At this stage, pressure is not a key parameter. As a result, unlike brown fields, less weight was given to simulated pressure, and SOI was used to select the well locations.
The results of this study show that implementing these workflows and obtaining the resulting maps significantly improve the selection process to identify the most productive areas and layers in a field. Also, the optimum numbers of wells using this method obtained in less time and with fewer resources are compared with results using traditional industry approaches.
Carbonate formations are very complex in their pore structure and exhibit a wide variety of pore classes. Pore classes such as interparticle porosity, moldic porosity, vuggy porosity, intercrystalline porosity, and microporosity. Understanding the role of pore class on the performance of emulsified acid treatment and characterizing the physics of the flow inside is the objective of our study.
The study was performed using vuggy dolomite cores that represent mainly the vuggy porosity dominated structure, while the homogenous cores represent the intercrystalline pore structure. Core flood runs were conducted on 6 x 1.5 in. cores using emulsified acid formulated at 1 vol% emulsifier and 0.7 acid volume fraction. The objective of this set of experiments is to determine the acid pore volume to breakthrough for each carbonate pore class at different injection rates.
In this paper, a novel approach to interpret the core flood run results using thin section observations, tracer experiments, SEM, and resistivity measurements will be presented. Thin section observations provide means to study the vugs size and their distribution, connectivity, and explain the contribution of the pore class in the acid propagation. Relating the rotating disk experiments of emulsified acid with dolomite to our core flood run results will be also conducted in order.
The acid pore volumes to breakthrough for vuggy porosity dominated rocks were observed to be much lower than that for homogenous carbonates (intercrystalline pore structure). Also, the wormhole dissolution pattern was found to be significantly different in vuggy rocks than that in homogenous ones. Comparison of thin section observations, tracer results and the core flood runs results indicates that the vugs are distributed in a manner that creates a preferential flow path which can cause a rapid acid breakthrough and effective wormholing than those with a uniform pore structure. Rotating disk experiment results, demonstrating that the reaction of emulsified acid with dolomite is much lower than that with calcite, showed that the reaction kinetics played a role in determining the wormhole pattern.
The demand for hydrocarbons is expected to grow worldwide. As a result, deeper reservoirs are being explored. Emulsified acid systems are preferred for the stimulation of high-temperature carbonate reservoirs with bottomhole temperatures (BHTs) of 275°F and above. The retarded nature of an emulsified acid system decreases both the acid reaction rate and the rate of corrosion. However, the lack of emulsion stability of these systems is a major problem associated with high-temperature applications (at 300°F and above).
Corrosion inhibitors and intensifiers can interfere with the stability of an emulsified acid system, which consequently leads to higher corrosion losses. At the same time, there is a need for better inhibition systems to counteract the effects of corrosion at higher temperatures. In this paper, a combination of three intensifiers was used, based on the differences in their mechanisms for inhibitor intensification action. The study includes the effect of varying the concentration of each component, hydrochloric (HCl) acid strength (20 to 28%), and temperature (275 to 325°F) on the stability and corrosion rate using P-110/N-80 coupons. The unique combination of the corrosion inhibitor and three intensifiers with proper optimization created a system capable of passing a corrosion test at 300°F using 28% HCl acid. The temperature limit of the system can be extended up to 325°F using an additional intensifier with 25% acid strength.
The present system can be used for acid stimulation of carbonate reservoirs with BHTs up to 325°F. This study revealed a better understanding of the effect of the intensifiers in an emulsified acid system and the synergism amongst them. This enabled the use of an emulsified acid stimulation on carbonate reservoirs having BHTs up to 325°F while reducing the corrosion rate to a level that meets the current market demand for acidizing operations. This work shows that emulsified acid systems can be used with HCl acid strengths ranging from 20 to 28% at high temperatures. The resultant better wormholing at high temperatures should also lead to enhanced oil production.
Acharya, Mihir Narayan (Kuwait Oil Company) | Kabir, Mir Md Rezaul (Kuwait Oil Company) | Al-Ajmi, Saad Abdulrahman Hassan (Kuwait Oil Company) | Pradhan, San Prasad (Kuwait Oil Company) | Dashti, Qasem M. (Kuwait Oil Company) | Al-anzi, Ealian H.D. (Kuwait Oil Company) | Chakravorty, Sandeep (Schlumberger)
The deep, sub-salt reservoir complex is tiered with fractured tight carbonate at bottom and top, with the two sub-units of "upper unconventional kerogen?? and "lower inter-bedded kerogen-carbonate?? in the middle. This depositional setting is challenging for horizontal well placement where the thicknesses of respective sub-units are about 50 and 30 feet with varying geomechanical and petrophysical properties. Additionally, this complexity poses limitations in completions and effective stimulation of the Kimmeridgian-Oxfordian reservoirs in several gas fields at development stage in Kuwait.
A horizontal well is placed in the lower sub-unit of the laminated complex of unconventional kerogen and fractured carbonate reservoir as a Maximum Reservoir Contact (MRC) type well. A pilot mother-bore was drilled and logged to identify the lithological properties across the entire vertical domain - facilitates the optimization of horizontal drain-hole placement within the targeted reservoir units.
No wellbore stability issues in drilling were predicted based on the geomechanical understanding where core-calibrated logs from offset vertical wells were considered. However, this modeling method did not have the functionality to integrate the impact of drawdown on the laminated formation which became unstable and collapsed during the short open-hole drill-stem test (DST) plugging the tubing prior to the final completions. An alternative "book-shelf?? geomechanical model was considered at pre-drill stage for predicting the wellbore stability. Once the drilling was completed, the time-lapsed multi-arm caliper indicated the validity of the alternative methodology in predicting the unstable stack of laminations in kerogen-rich strata.
The paper discusses an optimization methodology to enhance the understanding of static and dynamic geomechanical stability through the use of BHI data. Objective of the proposed method is to help improve the effectiveness of completions where wellbore stability due to geomechanical complexity in stacked-pay reservoirs is a primary wellbore challenge in deploying the completions and executing a subsequent stimulation and testing campaign.
A project study has been performed in order to evaluate a number of reservoir characterization and petrophysical parameters using Digital Rock Physics (DRP) technology in complex carbonate reservoir, on-shore Abu Dhabi. High-resolution images (X-ray micro-tomographic) of the rock's pores and mineral grains were obtained, processed and the rock properties were evaluated by numerical simulation of the physical processes of interest at the pore scale.
The selection of core samples in carbonate reservoir was performed with considering reservoir rock type, logs and routine core analysis data for validation and application phase. A set of special core analysis (SCAL) data were acquired earlier on the core samples in different carbonate reservoir rock types of varying levels of heterogeneity, lithology, porosity, and absolute permeability. This set of measurements formed the baseline for our validation study, then similar DRP approach and improvement is applied for non-SCAL cores. This process is used in DRP study to evaluate cementation exponents ‘m', saturation exponents ‘n', water-oil relative permeabilities, capillary pressures and elastic parameters such as compressional/shear wave velocities.
An integration of core and logs data in particular carbonate reservoir has been used to provide accurate and reliable results in the validation phase of DRP. It has been observed in DRP that connected micrite phase conductivity contribution has been determined for improvement approach by assigning a finite conductivity smic to the micrite phase to get reliable formation factor, cementation and saturation exponent. DRP and core J-capillary were integrated to provide reliable saturation-heights in this carbonate reservoir. The integration of formation evaluation in this case study has provided improvement, reliability in DRP results for formation evaluation and the potential to improve the quality and timeliness of carbonate reservoir characterization.
Ibrahim, Khalil (Abu Dhabi Marine Operating Co.) | Walia, Samir Kumar (Roxar ltd) | Matarid, Tarek Mohamed (Abu Dhabi Marine Operating Co.) | Al-Harbi, Haifa (Abu Dhabi Marine Operating Co.) | Afia, Mohamed Sayed (ADMA-OPCO) | Shaalan, Mohamed Essam (Roxar AS)
Defining the range of uncertainty is a crucial part in the oil field development particularly for carbonate reservoirs that have limited well data and with the absence of dynamic data. It is very important to develop an in-depth understanding of the range of uncertainty of all reservoirs parameters such as:
- Structure uncertainty
- Lithofacies and reservoir rock types
- Static reservoir attributes population technique (Porosity, Permeability, & Water Saturation)
Although outcrops and analogs are often employed to define reservoirs model parameters, it is still challenging to define and agree on the relationship between modeling parameters and their distribution ranges.
This paper addresses the impact of uncertainty of different modeling parameters on the volumetric calculations and full field development scenarios starting with structure model. Various areal and vertical uncertainties were investigated to set the structure uncertainty ranges. Then, the identified depositional environment models were used as guides to set the uncertainty ranges for each lithofacies association. The reservoir rock types were directly affected by both structure and lithofacies association models. Different ranges of variations were used for each rock type within each reservoir layer to ensure capturing the lateral and vertical reservoir heterogeneity and to propose multi distribution scenarios for each reservoir tock type within non-cored intervals/areas.
The petrophysical parameters were conditioned to the reservoir rock types model. So, they were directly affected by multi scenarios of RRT models.
In conclusion, 20 volumetric estimates were calculated and evaluated to define the probabilistic scenarios P10, P50, and P90 that will be used to investigate the full field development scenarios.
Understanding field uncertainty is crucial challenge affecting the decision making at the early stage of development of green fields. Challenges increase with limitation of core, log, and dynamic data as well as poor wells distribution overall the field.
This paper illustrates a case study of quantifying and evaluating the reservoir/field uncertainties using the advanced uncertainty tools and options of IRAP/RMS 3D modelling software. The workflow included structure modelling, facies distribution, porosity/permeability distribution, water saturation modelling and volumetric estimations.
Sugai Lilin oil field, located on the northeast flank of the South Sumatra basin. In 1933, operated by BPM, a discovery well (SLL-1) encountered productive Upper Talang Akar Sandstone which yielded 1365 BOPD with 0.219 MMSCFD gas from DST-1 and 1975 BOPD with 0.375 MMSCFD gas from DST-4. This field consists of two formation rock i.e. Talang Akar (sandstone, TAF) and Batu Raja (Limestone, BRF), both formations contain oil deposit with relatively small gas.
Depth of the top reservoir sandstone is about -775 m, with original pressure and temperature were 1294 psia and 78 C, respectively. Since 1934, this field started to produce oil from both formations, TAF and BRF. However, significant oil production rate of this field started in 1984, where the peak oil production rate reached 1800 bopd. The oil production drop very sharply to about 100 bopd with high water cut, in 2007.
From recent laboratorium EOR study, it showed that oil reservoir system in Baturaja limestone reservoir is considered as a strong oil wetting, especially in low permeability layer. This penomenon was also shown by value of the SOR which is greater than 35 %. In this kind of reservoir system, displacement by water will not result in increasing RF significantly, even viscosity of the oil is considered low. To improve oil production and oil recovery factor in this reservoir requires chemical injection which is able to alter the oil wetting to become non oil wetting system where the oil phase will flow much easily to. the wellbore. Using chemical solution of SEMAR, Huff n Puff approach has been implemented in ten (10) production wells in this Sungai Lilin Field. In this case, 3000 bbls of SEMAR solution with 2 % concentration was injected to each well, with 7 days of soaking. Responds of these huff and puff implementation varied among those wells, ranging from 50% to 400% increase in production peak.
Sungai Lilin oil reservoir is considered a medium density oil reservoir with oil gravity of about 29 oAPI. Cummulative oil production from this reservoir is about 25 % todate, which is still considered low. Lithology of this reservoir consists of two formations i.e. sandstone and carbonate rock. The carbonate reservoir in this field has a tight porosity of about 12 % in average. Oil phase found in the carbonate formation (Batu Raja Formation) is considered as an oil wetting system where chemical IOR is the best technique for increasing production in this field. Best alternative for IOR to be implemented in this field is chemical SEMAR injection where oil wetting can be altered to be non oil wetting. SEMAR (Solution by Chemical Modifier to Enhance Recovery) is a special chemical modified to accelerate recovery of oil fields. With a low concentration in a system, SeMAR has the ability to imbibe and alter the amount of energy on the surface or interfacial layers of the system. SeMAR is also a wetting agent that takes part on lowering the interfacial tension of a fluid and helps distribute the fluid on the rock surface.
Flank areas pose a particular field development challenge in giant fields with low dip where the transition zone is spread over a large area. Successful development of flank areas depends on accurate reservoir characterization, in particular, water saturation distribution in addition to the optimal placement of wells, both areally and vertically. In relatively thin reservoirs, horizontal wells are generally preferred to increase reservoir contact using lower well counts. Proper spacing and vertical placement of horizontal wells are, however, critical. Well spacing is closely linked to oil recovery, pressure support, and sweep efficiency. Similarly, placement of horizontal wells in the right layer is vital for maximum vertical sweep. In order to test initial concept in the field, two existing producers were converted into injectors and pressures were monitored at the offset producers. Surveillance showed that the injectors were able to support producers 1 km away. This paper describes the process of arriving at the optimal well placement for maximizing oil recovery in the flank areas. This study is applicable to giant oil fields with large flank areas which pose significant development challenges.
Al-Khaldi, Nasser Ali (Saudi Aramco) | Khamatdinov, Raphael A. (Al-Khafji Joint Operations) | Al-Otaibi, Mohammed Helayel (Al-Khafji Joint Operations) | Abdelrahim, Rabei Khalid (Schlumberger Middle East SA.) | Bouaouaja, Mohamed Tahar (Schlumberger)
Within an oil reservoir the water saturation height functions can vary strongly, especially for carbonate rocks. These variations can be significant and difficult to estimate. The amount of hydrocarbons in place, the prediction of recoverable oil, the recovery process and the future plans of developing such reservoirs depend on many factors, one of which is the accurate modeling of water saturation.
The Khafji carbonate reservoir is a heterogeneous reservoir with two different types of oil: light oil in the top of the reservoir and heavy oil in the bottom of the reservoir. The challenge of water saturation modeling is primarily in the heavy oil zone, where conventional height function techniques produces poor match against measured water saturation logs. Alternative methods were utilized in order to obtain good match in both light oil and heavy oil columns.
A workflow has been created in order to overcome these challenges. Laboratory derived capillary pressure curves were used to establish water saturation height relationships as a function of rock type (RT). Additionally, a Flow Zone Indicators (FZI) analysis was used as a basis for rock typing. Then a J-function derived from capillary pressure data for each rock type or hydraulic flow unit (HFU) was used to generate saturation height function for each RT. The generated saturation undergone via several iterations to match the large span of openhole electric water saturation logs above the free-water level (FWL).
The saturation profile generated by this workflow shows a good match to the measured Sw electric logs, and the calculated fluid volumes are in agreement with company's approved reserves estimation.
Liu, Yimou (China University of Petroleum) | Liang, Xianghao (Petrochina Tarim Oilfield Company) | Zhou, Yi (Petrochina Tarim Oilfield Company) | Wang, Yanfeng (BGP, CNPC) | Chen, Xueqiang (BGP, CNPC)