Timely and detailed evaluation of in-situ hydrocarbon flow properties such as oil density and viscosity is critical for successful development of heavy oil reservoirs. The prediction of fluid properties requires comprehensive integration of advanced downhole measurements such as nuclear magnetic resonance (NMR) logging, formation pressure, and mobility measurements, as well as fluid sampling.
The reservoir rock presented in this paper is an unconsolidated Miocene formation comprising complex lithologies including clastics and carbonates. The reservoir fluids are hydrocarbons with significant spatial variations in viscosity ranging from (60-300 cP) to fully solid (tar). Well testing and downhole fluid sampling in this formation are hindered by low oil mobility, unconsolidated formation that generates sand production, emulsion generation, and very low formation pressure.
We present a two-pronged log evaluation workflow to identify sweet spots and to predict fluid properties within the zones of interest. First, the presence of "missing NMR porosity" and "excess bound fluid" is estimated by comparing the NMR total and bound fluid porosity with the conventional total porosity and uninvaded water-filled porosity logs, respectively. Secondly, two-dimensional NMR diffusivity vs. T2 NMR analysis is performed in prospective zones where lighter and, possibly, producible hydrocarbons are detected. The separation of oil and water signals provides a resistivity-independent estimation of the shallow water saturation. Additionally, we correlated the position of the NMR oil signal with oil-sample viscosity values. The readily available log-based viscosity greatly improves the efficiency of the formation and well-testing job.
We successfully sampled high viscosity hydrocarbon fluids by utilizing either oval pad or straddle packer. The customized tool designed for sampling aided gravitational segregation of clean hydrocarbons from the water-based mud filtrate and emulsion; and therefore providing representative reservoir fluid samples based on downhole fluid analyzers.
In this study, a review of production performance of four existing horizontal producers equipped with Inflow Control Device (ICD) completions was conducted using 4-D dynamic modelling on a sandstone reservoir with high water mobility. The aim of this study was to investigate the optimum regulation degree across ICD completion i.e. the ratio of pressure drop across ICDs to the reservoir drawdown, suitable to delay water breakthrough, minimize water cut and achieve production balance.
A single wellbore model was built by populating rock and fluid properties in 3-D around the wellbore for each of the studied wells. The model was then calibrated to the measured production log flow profile and bottomhole pressure profile for the deployed ICD completion in each well. Thereafter, several ICD simulation cases were run at target rates for a production forecast of 4 years. An optimum ICD case for each well was selected on the basis of water breakthrough delay, water cut reduction and incremental oil gain.
The study results showed that there is a correlation between reservoir heterogeneity index, well productivity index (PI) and optimum regulation degree required across ICD to achieve longer water breakthrough delay and better water cut control. In general, high heterogeneity, high PI wells require higher regulation degree across ICD of close to one; medium heterogeneity, low PI require regulation degree across ICD of between 0.3 – 0.45 while low heterogeneity, low PI, require very low regulation degree of between 0.1 – 0.15. Based on study results, a new ICD design framework and correlation chart were developed. This framework was then applied to two newly drilled horizontal producers to test the applicability of the workflow in real time ICD design scenarios and positive results were achieved.
Given the significant number of ICD completions deployed yearly, this new ICD design framework would provide guidance on how much pressure drop across ICD is required during real time design for newly drilled or sidetrack wells and would ultimately ensure maximum short and long term benefits are derived from deployment of ICD completions.
In Kuwait, the traditional approach to Field Development has been to drill wells, whether Vertical or Horizontal, Single or Dual, with completions dedicated to either Production or Injection. However, as increasingly more wells are being drilled to develop the stacked reservoirs, surface infrastructure is growing in complexity with regard to Production Flowline routing, Gathering Facility location, Satellite Manifold placement, Water Injection distribution lines routing, and access road construction. Also, since the reservoir stack is a combination of areally extensive Carbonates overlying shale & channel sand sequences, optimum surface locations of Injectors for one reservoir is now increasingly conflicting with the optimum surface locations for the Producer of another reservoir.
The North Kuwait team presented options that could reduce the requirement for excessive wellbores for both new Producers and Injectors. One of which is the utilization of a single wellbore to both Produce Oil from one reservoir and Inject Water into another reservoir simultaneously. This novel approach utilized the most popular Dual Completion equipment, but rather than produce or inject concurrently from separate reservoirs or layers, production & injection are achieved simultaneously through either tubing string. Tubing movement calculations were made to ensure that the resultant axial tubing forces exerted by simultaneously injecting cold water and producing hot reservoir fluid would not cause the Dual packer to prematurely unset.
This unique completion has several advantages which include the production acceleration from an adjacent reservoir/layer that would have been postponed for the life of the Injector and the elimination of the drilling of a new producer to access the oil from an adjacent reservoir/layer to the target injection zone. Additionally, the elimination of the drilling of an Injector well if its optimum subsurface location is close to, or coincides with, an existing Producer from an adjacent layer, and the reduction in access road construction and location preparation costs. This strategy will significantly reduce Unit Development Costs while concurrently ramping up production levels. With simple conversion workovers, rather than drilling new wells, Oil Production potential that is presently unexploited in dedicated Injector wells can immediately be realized. Pressure support Injection can be initiated as soon as distribution injection lines are made available via similar conversion workovers.
Al-Houti, Naser (Kuwait Oil Company) | Al-Othman, Mohammad (Kuwait Oil Company) | Al-Qassar, Khalid (Kuwait Oil Company) | Al-Ebrahim, Ahmed (Kuwait Oil Company) | Matar, Khaled (Halliburton) | Al Hamad, Abdulla (Halliburton)
This paper presents the application of a unique gelling system for perforation shut-off operations that can help reduce operational time by 50% and can also be used as an effective water- and gas-migration control agent. The system combines a conformance sealant (based on an organically crosslinked polymer) with non-cementious particulates. The particulates provide leak-off control, which leads to shallow matrix penetration of the sealant. The filtrate from the leakoff is thermally activated and, as a result, forms a three-dimensional (3-D) gel structure that effectively seals the targeted interval after exposure to the bottomhole temperature (BHT).
The traditional method for recompleting wells into newer layers, after the current producing zones have reached their economic limit, involves several steps. The first step is to squeeze off the existing unwanted perforations using cement, drill out the cement across the perforations, and then pressure test the squeezed zones to help ensure an effective perforation seal has been achieved. The new zones are then perforated and completed for production. The entire operation can require four or more days of rig time, depending on the success of the cement squeeze. In cases of cement failure, the required time can extend to over one week. Common challenges associated with cement-squeeze operations include leaky perforations, fluid migration (gas or liquid) behind the pipe, or compromises in the completion. Attempts to remediate these issues must be repeated until all objectives are met.
The new perforation plugging system can be bullheaded into the well (spotted at a desired location in the wellbore), allowing for easy placement and calculation of the treatment volume. The limited and controlled leakoff into the matrix during the squeeze results in a controlled depth of invasion, which allows for future re-perforation of hydrocarbon-producing zones. The system can be easily washed out of the wellbore, unlike cement, which must be drilled out. The temperature range of the particle-gel system is 60 to 350°F, which makes it versatile.
To date, more than 500 operations have been performed with this system globally. This paper presents the results obtained from laboratory evaluations, the methodology of the treatment designs, and four case histories from Kuwait. A salient case is the successful use of the sealant/particulate system, resulting in shutting off all perforations after six failed cement-squeeze operations.
The prospect of reducing the required time to perform remedial cement-squeeze operations by 50%, as well as the ability to repair casing leaks and seal off thief zones, make this sealant/particulate system a valuable alternative to standard cement-squeeze operations.
Ratnakar, Ram R. (Shell International Exploration and Production Inc.) | Mantilla, Cesar A. (Shell International Exploration and Production Inc.) | Dindoruk, Birol (Shell International Exploration and Production Inc.)
Wettability alteration due to asphaltene precipitation in a reservoir affects rock-fluid interactions that have potential impacts on oil production, recovery and flow in the production network. The current predictive wettability models do not consider asphaltene stability and are inherently inaccurate. This study investigates the impact of pressure-depletion induced asphaltene precipitation on interfacial tension (IFT) and contact angle for live-oil systems at reservoir conditions (high-pressure high- temperature); and presents a graphical (quantitative) method for determining asphaltene onset pressure based on interfacial behavior.
Water/oil IFT was measured at reservoir temperature using pendant drop-shape method for a system of live-oils over a range of pressure above and below the asphaltene onset pressure (that was already independently determined via particle size distribution and solid detection system techniques). Contact angle with quartz was also measured in presence of de-ionized water as surrounding medium at the same pressure and temperature conditions. The temperature was controlled with an accuracy of ±0.1°C. Each set of measurements were performed twice to assure the reproducibility of the experiments and methodology.
This work presents the experimental study to quantify the change in interfacial behavior due to asphaltene deposition. The IFT/Contact Angle measurements above and below asphaltene onset pressure show that the interfacial behavior follows the normal trends above asphaltene onset pressure as observed in other water/hydrocarbon systems. However, when pressure was reduced below the asphaltene onset pressure, an evident relatively sharp change in the trend is observed in both IFT and contact angle caused by asphaltene migration to the interface, in a way acting as natural surfactant. As asphaltenes precipitate and deposit in the mineral substrate, the surface turns less water-wet and the contact angle naturally increases to balance the equilibrium forces.
This study sets a non-visual quantitative method to determine asphaltene onset pressure and presents new experimental data on IFT/contact angle of live-oil systems at reservoir conditions. The effects of asphaltene precipitation on interfacial properties are more meaningful than the size of aggregates (visual methods), and can be utilized to assess the potential impacts of wettability alteration due to asphaltene precipitation. For example, only when change in contact angle is large, wettability alteration should be considered in reservoir simulation of depletion processes and waterflooding performace, especially in the context of relative permeability changes.
Zhang, Fan (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development) | Ma, Desheng (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development) | Tian, Maozhang (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development) | Luo, Wenli (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development) | Zhu, Youyi (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development) | Luo, Yousong (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development) | Liu, Wanlu (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development)
Reservoirs of high viscosity and low permeability are abundant and widely distributed in various countries, which can contribute an important percentage of oil output in the world. Conventional chemical flooding are suitable for low viscosity oil (less than 30 mPa·s) and medium/high permeability reservoirs (more than 50mD). However, it is a great challenge to applied chemical flooding technology for higher viscosity (30-500mPa·s) oil and lower permeability (1-50mD) reservoirs. On the one hand, the high contents of resin and asphaltene, or the formation of wax crystals in low reservoir temperature, lead to high oil viscosity and low oil recovery; On the other hand, low permeability can cause injection difficulty, and conventional chemical agents (polymers and formulations of chemical combination flooding) are difficult to inject. At present, the main exploitation mode is water flooding. However, because of high oil viscosity and low oil fluidity, the water flooding recovery is only about 15%. So it is very necessary to develop effective development technology.
It is a good choice to develop water flooding with the intelligent viscosity reducer to decrease oil viscosity and improve oil fluidity, which has small molecular weight and can inject low permeability reservoirs easily. The performances of the viscosity reducer were studied in detail, including viscosity reduction efficiency, tripping oil film capacity, interfacial property, oil-displacement efficiency etc. The novel viscosity reducer with intellectual property show excellent properties. The viscosity reduction efficiency of the viscosity reducer was more than 80% (from 64.4 mPa·s to 10.3 mPa·s), and it could strip oil film within 40 seconds quickly, and could achieve ultra-low Interfacial Tension (IFT, less than 1.0×10-2mN/m). Alkali (NaOH or Na2CO3) could help to increase the viscosity reducing effects, and improve the stripping oil film capacity and interfacial property. The viscosity reducer had high oil-displacement efficiency; after water flooding, Oil recoveries increased 23% (OOIP, Original Oil In Place) with thehelp of this viscosity reducer. The novel viscosity reducer has viscoelasticity and shear-thinning ability. The monomer molecules can form the three-dimensional network structure in aqueous solution with high viscosity, which plays a role in enlarging the swept volume. With the increase of the shear rate, the three-dimensional network structure is broken down into the monomer molecules, and the viscosity decreases rapidly, so the viscosity reducer solution can inject low permeability reservoir easily. Compared with conventional polymer and polymer-surfactant, this viscosity reducer solution had better shear resistance and injectivity, and could filter membrane (0.2μm pore) effectively.
The novel viscosity reducer with intellectual property show excellent properties. The viscosity reduction efficiency of the viscosity reducer was more than 80% (from 64.4 mPa·s to 10.3 mPa·s), and it could strip oil film within 40 seconds quickly, and could achieve ultra-low Interfacial Tension (IFT, less than 1.0×10-2mN/m).
Alkali (NaOH or Na2CO3) could help to increase the viscosity reducing effects, and improve the stripping oil film capacity and interfacial property.
The viscosity reducer had high oil-displacement efficiency; after water flooding, Oil recoveries increased 23% (OOIP, Original Oil In Place) with thehelp of this viscosity reducer.
The novel viscosity reducer has viscoelasticity and shear-thinning ability. The monomer molecules can form the three-dimensional network structure in aqueous solution with high viscosity, which plays a role in enlarging the swept volume. With the increase of the shear rate, the three-dimensional network structure is broken down into the monomer molecules, and the viscosity decreases rapidly, so the viscosity reducer solution can inject low permeability reservoir easily.
Compared with conventional polymer and polymer-surfactant, this viscosity reducer solution had better shear resistance and injectivity, and could filter membrane (0.2μm pore) effectively.
The novel viscosity reducer can substitute for conventional polymer and polymer-surfactant in chemical flooding. This paper provides insights of a new effective EOR way for high viscosity and low permeability reservoirs.
Guo, Erpeng (Research Institute of Petroleum Exploration and Development, CNPC) | Jiang, Youwei (Research Institute of Petroleum Exploration and Development, CNPC) | Gao, Yongrong (Research Institute of Petroleum Exploration and Development, CNPC) | Shen, Dehuang (Research Institute of Petroleum Exploration and Development, CNPC) | Zhigang, Chen (Changqing Oilfield, CNPC) | Yu, Pengbo (Jinma Company Liaohe oil field. CNPC.)
SAGD (Steam Assisted Gravity Drainage) is commercially adopted as a main development methods for heavy oil reservoirs and oil sands. Improving recovery rate and heat efficiency of SAGD process is the main pursuit of all researchers. This paper aims to utilize a new additive with carbamide to reduce the steam consumption and lower down the residual oil saturation, hence to improve the recovery efficiency of this method.
Study on improving recovery efficiency of SAGD with carbamide in super heavy oil reservoir was carried out. 1-D flooding experiment were carried out at 50°C and 150°C to compare the sweep efficiency between different additives including carbamide, CO2 and alkali. Then simulation were run to evaluate the influence of carbamide to SAGD process. Different additives were compared and influences of different products from carbamide were analyzed in detail.
Study reveals that SAGD process can be greatly influenced by carbamide. Carbamide can gradually decompose into ammonia and CO2 in steam chamber. Great solubility of ammonia in water can effectively increase PH value of reservoir liquid and decrease residual oil saturation. The core flooding test results show that the oil displacement efficiency can be improved by 17.7% when 25% mass percent of carbamide was added at 150°C. And at 50°C, NH4OH showed 9% improve of sweep efficiency comparing to water. Solution of CO2 into oil can improve oil water mobility ratio. And in the simulation case the oil saturation in the core part of steam was reduced to 0.12 by ammonia (this value is 0.2 for steam). Distribution of CO2 and ammonia shows that oil drainage maybe start with viscosity reduction with CO2 solution and ends with ammonia flooding in steam chamber. With the result of this paper, the recovery factor of SAGD process can be improved by 15.4% and SOR can be improved by 20% when carbamide was co-injected with steam.
In mature oil fields, water, steam, natural gas, and carbon dioxide are purposely injected into a reservoir to increase pore pressure on the oil, to lower the viscosity of heavy oil, and, ultimately, to increase the oil recovery factor. The placement of oil, water, and gas within the reservoir is highly dynamic and not easily predicted. Therefore, reservoir monitoring is key to improving sweep efficiency and oil recovery.
Density is an important physical property for inferring oil, water, and gas saturation in a rock. Due to the density differences of oil, water, and gas, the saturation variation of each phase will have a direct impact on the measured gravity fields. The conventional well logging tool, gamma-gamma density, has a maximum depth of investigation (DOI) of 6 to 8in in open hole and greatly reduced accuracy in cased hole. A gravimeter, in contrast, yields a density measurement with inherently large DOI, where the DOI is determined by the vertical separation between pairs of differenced measurements of the acceleration due to gravity. For example, the DOI resulting from a pair of measurements separated by 3m will be approximately 4.5m.
In this paper, we have conducted extensive simulations of using borehole gravity fields to monitor water flooding from injectors. In one scenario, we considered fracture systems within the reservoir typically identified by seismic methods; however, their impact on water flooding is not fully understood. Borehole imaging and production logging measurements clearly identify where fractures are along the borehole. However, due to their limited DOI, there is no clear picture about fractures farther from the borehole. Because the fractures are most probably filled with water and rock other than formation rock, which have a density different from that of the surrounding formation matrix, the borehole gravity field with its large DOI could provide useful information. To understand the response and the sensitivity of the borehole gravity measurements, we constructed a reservoir model with fractures of different sizes and locations within the modeled volume. From the lithology and fluid properties, density information was computed and propagated in the model. A vertical well was used as the survey location of the borehole gravity measurements. Both gravity and differential fields were calculated. The simulations were designed to address the following questions: Does the borehole gravity measurement have enough sensitivity to detect fractures within a reservoir? How far away from a borehole can fractures be accurately identified?
Does the borehole gravity measurement have enough sensitivity to detect fractures within a reservoir?
How far away from a borehole can fractures be accurately identified?
This paper will present our simulation results and discuss their implication for reservoir fluid-front monitoring. Although borehole gravity measurements have not been used in reservoir monitoring, this study's results demonstrate the advantage of data acquisition with large DOI, which provides a huge operational benefit and cost-effective measurements to manage oil fields.
Calcium sulfate is inherently a difficult mineral scale during oil and gas production process because the amount of scale formed is much greater than that of barium sulfate at similar scale saturation index level, and it is very difficult to clean up. This is especially challenging in conjunction with HTHP stimulation treatments where compatibility of the scale control chemical with fracturing fluids is critical, and when longer-term inhibition performance is desired. A new solid inhibitor was developed for this purpose and applied in multiple wells in the Krishna Godavari (KG) basin offshore India to combat mineral scale within the proppant pack and production tubing over the long term, under extreme downhole conditions (T= 400°F, P=13,500 psi). Normally, downhole chemical injection mandrels and surface treatments cannot adequately control scale deposition under these conditions.
The new solid inhibitor product was made by adsorbing scale inhibitor onto a high-strength, proppant-sized substrate with a large surface area. The high-strength substrate were prepared by sol-gel chemistry through hydrolysis of aluminum alkoxides and formation of particles that are calcined and then sintered at high temperatures to produce a substrate with the desired strength and surface area. The scale inhibitor used exhibited excellent inhibition performance and good compatibility with metal based cross-linked fracturing fluid systems at high temperature.
Tests performed with proppants/substrates show that using high loading of the substrates with the proppant does not damage the proppant pack even under very high stresses, For example, API crush tests of a mixture of 80% conventional untra-high strength proppant with 20% substrate by weight at 13,000 psi produced less than 4.7% fines and 88% of the produced fines were larger than 100 mesh and the fracture conductivity of the pack is maintained. The results of comprehensive laboratory testing show the new solid inhibitor can prevent anhydrite scale up to 400°F, and is completely compatible with zirconium- crosslinked fracturing fluid at 350°F and above. To date, six fracture treatments have been performed using a total 23,800 lbs of this new solid inhibitor. The wellhead water samples are being collected for scale inhibitor residuals analysis, as the wells start to produce water.
To ensure compatibility of the inhibitors with high-temperature fracturing fluids, especially metal based cross-linked fracturing fluids, without compromising the inhibition longevity at high pressure and temperature remains a stiff challenge, although adding scale inhibitors to a fracturing fluid has been a well-established practice to provide long-term inhibitor protection during hydrocarbon production. The new approach described here meets this objective, extending the long-term well performance under HTHP conditions.
Rashaid, M. (KOC) | Al-Ibrahim, M. (KOC) | Van Steene, M (Schlumberger) | Ayyad, H (Schlumberger) | Friha, A. (Schlumberger) | Liang, L. (Schlumberger) | Cig, K. (Schlumberger) | Ayan, C. (Schlumberger) | Habashy, T. (Schlumberger) | Cherian, J. (Schlumberger)
Relative permeability and capillary pressure are essential information for reservoir modeling, as they impact production optimization and reservoir management. Obtaining this data from special core analysis can take a significant amount of time. Furthermore, it can be challenging to guarantee that the core is restored to its original reservoir wettability state. Additional challenges include cost, scale, and the presence of contamination or alteration. Other emerging techniques, like digital rock, face similar issues. A new workflow has been designed to address those challenges and complement the traditional core analysis offering, by obtaining relative permeability and capillary pressure in-situ from wireline formation tester (WFT) and open hole logging measurements.
In this workflow, a near-wellbore reservoir model is built to simulate the mud-filtrate invasion. This reservoir model, combined with an electromagnetic model, simulates resistivity logs, and subsequent pressure transient and mud-filtrate cleanup processes induced by WFT formation testing. Petrophysical log analysis, using array resistivity, nuclear magnetic resonance, and dielectric measurements, is performed to provide prior information for the model initialization. Vertical interference testing from WFT at the same depth provides permeability anisotropy. An optimization engine is employed to update the selected reservoir model parameters until the simulated resistivity logs, pressure transient, and water-cut data match their measured counterparts. Relative permeability and capillary pressure are estimated together with other parameters including mud-filtrate invasion volume and permeability. Both stochastic and deterministic methods are used for the inversion. The deterministic method is cost-effective if a good initial model can be obtained, while the stochastic method is able to find the minimization function's global minimum but needs high computational effort.
This workflow was applied to one well in the Ahmadi field in Kuwait, targeting an inter-tidal deposit. In-situ relative permeability and capillary pressure curves were obtained by the deterministic and stochastic methods using formation testing data and petrophysical logs acquired over the interval. The results are consistent between the two methods and representat the effective formation properties in the surveyed interval.
This case study demonstrates that it is possible to obtain in-situ relative permeability and capillary pressure data from commonly acquired wireline measurements. The delay in obtaining the relative permeability and capillary pressure data is significantly reduced compared to special core and digital core analysis techniques. Since the measurement is performed downhole, it doesn't suffer from the doubts that surround the core samples restoration process to original reservoir conditions. The formation volume investigated by this survey, in the order of several feet, represents the formation macroscopic properties, thus bridging the gap between core scale and reservoir scale.