Steam Huff Research Articles

Influence of Deposition Characteristics in the Heavy Oilfield Development Stage

III oil formation of He3 section of block 1 in Jinglou Oilfield has entered the mid-late stage of oilfield development after years of steam huff and puff production. The distribution of remaining oil is scattered. This paper combines the data of core, well logging, seismic and development performance to analyze the reservoir heterogeneity. It reveals the impact on oilfield development. The area is mainly fine sandstone, siltstone and inequigranular sandstone, belonging to the river sediments, the development of fan delta and fan delta front subfacies. The heterogeneity of reservoirs and sedimentary microfacies are closely related, with moderate - strong. Well spacing near the larger region between the well and well pattern is not perfect in southern area and fault is the main purpose of tapping the potential of remaining oil in the next area.

A Study on the Technology of Steam - Hot Water - Nitrogen Compound Drive after Steam Channeling in Steam Flooding

Nowadays most heavy oil reservoirs are developed by thermal recovery methods, such as steam huff - puff and steam flooding. At the late stage of heavy oil steam drive, because of steam overlap in the upper reservoir formation, steam channeling can easily occur in production well. The research has shown that development effect of steam - nitrogen compound drive is not as good as consideration after steam channeling. But by injecting water slug can decrease the effect of steam channeling. For increasing water phase saturation in high permeability channel, steam and nitrogen gas relative permeability will decrease. As result, it will enlarge the reservoir vertical producing degree, and at the same time take full advantage of the oil displacement effect of steam - nitrogen compound drive. Through the numerical simulation, the study found that, steam - water - nitrogen compound drive technology can achieve better recovery degree using high hot water temperature and shorter injection time.

Methods Study on Gas Channeling of <i>In Situ</i> Combustion Development in Developed Heavy Oil Reservoir

Now in situ combustion became one of the ways for the developed heavy oil reservoirs to convert development pattern and improve recovery. After long time steam huff and puff development in heavy oil reservoir, it was obvious that there was a big change on the oil zones and reservoir properties and the reservoir heterogeneity. When it was converted to in situ combustion, the injection gas often break through along the high permeability layers in the fire drive wells that make the sweep area smaller and decrease the reservoir recovery. By analysis on the gas channeling of in situ combustion occurred in the heavy oil reservoirs, the methods was put forward to develop heavy oil reservoir using in situ combustion reasonably including well space infilling, controlling the gas injection rate, adding roam surfactant agent and using fire drive with horizontal well assisted etc. to prevent the condition of gas channeling occurring. It will greatly improve the success and adaptability of the in situ combustion used in vertical wells of the heavy oil reservoir by using these methods. It also will build on basis of the heavy oil reservoir converted to in situ combustion development.

Horizontal well, nitrogen and viscosity reducer assisted steam huff and puff technology: Taking super heavy oil in shallow and thin beds, Chunfeng Oilfield, Junggar Basin, NW China, as an example

Abstract Chunfeng Oilfield in the Junggar Basin has shallow burial depth (400–570 m), low formation temperature (22–28 °C), thin reservoirs (2–6 m, averaging 3.5 m), high underground crude oil viscosity (50 000–90 000 mPa·s), but high sensitivity to heat, it is suitable for thermal recovery. In view of these features, a development method for this oilfield combining horizontal well, viscosity reducer, nitrogen and steam flooding (HDNS) was put forward, and pilot test was carried out in Northern Pai 601 sand body. The results show: injecting nitrogen through annulus can insulate thermal, high expansibility of nitrogen works to compensate formation energy, and nitrogen overlapping in reservoir has insulation effect. The combination effect of all parts of HDNS significantly increased steam sweep volume, oil displacement efficiency and crude oil flow ability, and reduced oil viscosity. Thanks to this technique, Chunfeng Oilfield has built up a production capacity of 40×104 t, with an oil recovery rate of 3%, marking the successful high-speed and high-efficiency development of low-grade shallow thin super heavy oil.

Optimization of Superheated Steam Huff and Puff Wells Sequence in Heavy Oil Reservoir

Production of superheated steam huff and puff wells is affected by reservoir geological characteristics (effective thickness, net gross ratio), the state of development (recovery degree, integrated water-cut) and steam injection parameters (intensity of steam injection, steam injection rate, temperature and degree of superheat. etc.). On the basis of analysis of each factor, All factors set were established by a new specified model and the weight of each factor was determined by the functional correlation between the factors and production of each well. The integrated measured value of all factors was calculated by dimensionless value of each factor through integrated evaluation methods. Statistics results showed that the oil production of each well has perfect proportional relationship with the integrated measured value of all factors, there is the higher the integrated measured value of all factors, the higher the oil production of each well. According to this good correspondence, the integrated evaluation template was formed, and the total coincidence reached 96% with high reliability in the practical application in the Kenkiyak Oilfield, Kazakhstan.

Significant Superiorities of Superheated Steam in Heavy Oil Thermal Recovery

With superheated steam there is no direct relationship between temperature and pressure, and it can exist at a wide range of temperatures. Superheated steam with high degree( >50 °C) of superheat has similar thermal physical characteristics with ideal gas and the heat transfer coefficient is 1/150-1/250 as much as that of saturated steam during heat transferring. It could release less energy and transmitted longer distances than that of saturated steam in heavy oil reservoirs. Numerical simulation shows that under the condition of carrying the same heat, superheated steam huff and puff enlarged the heating radius by about 10 m, oil production increment by 1463 t, oil steam ratio increase by 0.7. Superheated steam huff and puff was put into Kazakstan's heavy oil reservoir after saturated steam huff and puff and the average daily oil production was 2-4 times that of saturated steam huff and puff, which improved heavy oil production effectively. The secondary heavy oil thermal recovery by superheated steam huff and puff applicated in marginal heavy oil reservoirs achieved satisfactory effect.

CO 2 and viscosity breaker assisted steam huff and puff technology for horizontal wells in a super-heavy oil reservoir

Abstract In order to improve the recovery effect of steam huff and puff in a super-heavy oil reservoir, the displacement efficiency of CO 2 and viscosity breaker assisted steam flooding was studied through in-lab displacement experiments. The viscosity reduction mechanism of CO 2 and viscosity breaker assisted steam huff and puff for horizontal wells was realized by numerical simulation. The results show that the displacement efficiency of CO 2 and viscosity breaker assisted steam flooding (80.8%) is higher than that of steam flooding (65.4%). The CO 2 and viscosity breaker assisted steam huff and puff technology for horizontal wells realizes the rolling replacement of viscosity reduction of viscosity breaker, CO 2 and steam, thus effectively reducing the steam injection pressure, expanding the steam sweep area, i.e., expanding the viscosity reduction region and improving oil production rate. The viscosity region can be divided into four compound viscosity reduction areas according to temperature distribution and viscosity reduction mechanism. They are steam compound viscosity reduction region, hot water compound viscosity reduction region, low temperature water compound viscosity reduction region, and CO 2 -viscosity breaker compound viscosity reduction region. Field tests show that the CO 2 and viscosity breaker assisted steam huff and puff technology for horizontal wells is effective in reducing viscosity and improving production of super-heavy oil reservoirs with deep and thin layers, deep and heavy layers, shallow and thin layers.

Multi-combination exploiting technique of ultra-heavy oil reservoirs with deep and thin layers in Shengli Oilfield

There isn't any mature technique to develop ultra-heavy oil reservoirs in the Shengli Oilfield because of large oil viscosity, deep and thin layer, high rate of resin and asphaltene. The multi-combination exploiting technique is developed which combines the techniques of under-pressure foam flow-back, efficient oil-soluble viscosity reducer, CO2 immiscible and steam huff and puff. The following experiments were conducted about the recovery mechanism of the technique: (1) measuring foam viscosity, sands suspension property and sands washing capacity; (2) comparing the capacities of viscosity breaking and emulsion breaking of oil-soluble viscosity reducer with the conventional viscosity reducer; (3) measuring emulsion breaking of CO2. The experimental results show: Foam has the advantages of greater viscosity, remarkable capacities of suspending and washing sands; the combination viscosity reducer has greater advantage on viscosity breaking over xylene. The emulsion breaking capacity of the combination viscosity reducer and CO2 is excellent, and the higher the W/O emulsion, the greater the capacity of emulsion breaking. Field tests show that the multi-combination exploiting technique is good in improving production of ultra-heavy oil reservoirs. ： 胜利油田超稠油埋藏深、储集层薄、原油黏度大、胶质和沥青质含量高，采用目前成熟的稠油开发方式无法有效动用。结合超负压泡沫混排技术、高效油溶性降黏剂降黏技术、CO2非混相驱油技术和蒸汽吞吐技术，提出深薄层超稠油多元复合开采技术。针对多元复合开采技术的开采机理，进行相关实验：①测定泡沫黏度以及泡沫悬砂、冲砂性能；②油溶性复合降黏剂与常规降黏剂降黏效果对比实验和破乳实验；③CO2破乳能力实验。实验表明：泡沫具有良好的悬砂、冲砂性能；复合降黏剂的降黏效果远好于二甲苯，复合降黏剂和CO2均具有很好的破乳效果，原油乳化程度越高，破乳效果越好。现场试验显示多元复合开采技术开发深薄层超稠油具有良好效果。图5表4参14

An integrated evaluation on factors affecting the performance of superheated steam huff and puff in heavy oil reservoirs

Abstract Production of superheated steam huff and puff wells is affected by reservoir geological characteristics (effective thickness, net gross ratio), the state of development (recovery degree, comprehensive water-cut) and steam injection factors (strength of steam injection, steam injection rate, temperature and degree of superheat), etc. On the basis of analysis of each factor, factors set were established and the weight of each factor was determined by the functional correlation between the factors and production of each well. The measured value of each factor was computed by dimensionless analysis of each factor. The comprehensive measured value of all factors was computed by dimensionless value of each factor through comprehensive evaluation methods. Statistics showed that the higher the comprehensive measured value of all factors, the higher the oil production of each well. According to this good correspondence, the comprehensive evaluation template was formed, and the total coincidence reached 96% with high reliability in the practical application in the Kenkiyak Oilfield, Kazakhstan.

Casing Cementing with Internal Pre-pressurization for Thermal Recovery Wells

Abstract Thermal recovery is a very common and effective method for producing heavy oil. Casing failure is a very serious problem in thermal recovery wells. In some oilfields, more than 95% of the casing for thermal recovery wells failed due to thermal stresses. In the steam injection process, the casing is heated by steam. The change in casing temperature produces thermal stresses. The casing deforms when stresses exceed the yield point of its material. If using conventional cementing technology for thermal recovery wells, the casing will deform as a result of thermal stresses as a result of the steam injection process. Conventional technologies used to protect thermal recovery well casing from failure are theoretically ineffective. Casing cementing with internal pre-pressurization for thermal recovery wells refers to the exertion of inner pressure on payzone production casing to make payzone production casing expand in the cement solidifying period. Calculations show that casing with internal pre-pressurization technology achieves a greater safety coefficient during the whole production cycle and results in no plastic deformation. This technology will be an important method to prolong thermal recovery well casing life. Introduction Steam injection is a common and effective operation to recover heavy oil. It has been adopted by many oil fields in China, including the Liaohe Oil Field and the Shengli Oil Field. It comes in two forms: steam huff and puff and steam drive. These two methods follow the same processes. First, run insulated tubing to the oil layer and fix it to the casing with a packer. Then, inject nitrogen into the annular space between the tubing and the casing. Finally, inject saturated steam into the oil layer through insulated tubing using injection equipment. The operating mechanisms are different, however. With the first method, injected saturated steam will transfer heat to the formation, thinning out the crude oil and raising the reservoir pressure. After the well is sealed for a short period, it will begin production. With the latter method, saturated steam will drive crude oil into the bottom of the production wells. During the steam injection period, thermal stress is produced by the temperature increasing in the casing string downhole, which may lead to the plastic yielding. The casing may deform due to thermal stress, uneven external pressure and heterogeneity in the casing itself(1–7). After production begins, the downhole temperature gradually decreases, elastic stress in the casing string declines and the plastic deformation remains. The result is that axial tensile stress often makes the casing thread off. Current cementing technologies for protecting casing from failure for thermal recovery wells, such as pre-tension stress, slipjoint casing and preheating the whole well, are proven to be not so effective in solving deformation failure of the casing caused by overheating(8). Thus, the authors of this paper developed a safe and operable method to protect thermal recovery well casing from failure, using, in part, pre-heating cementing technology for thermal recovery wells(9), as well as pre-pressurized cementing for thermal recovery wells(10). These technologies keep the production casing in an elastic state for the entire thermal recovery operation. The procedures for casing cementing with internal pre-pressurization for thermal recovery wells are as follows: when finished pumping the cement slurry, run the drillstring with packer at its lower end to the top of the payzone casing, set the packer, then add additional pressure from the surface to the payzone production casing through the drillstring, tripping

Application of material balance method to nitrogen anti-water-coning technology

Abstract Nitrogen anti-water-coning is simplified into two processes of gas driving oil and oil driving water based on the mechanisms of nitrogen repressing water coning and enhancing oil recovery. Material balance method is employed to study nitrogen anti-water-coning technology in heavy oil reservoirs with bottom water and multi-periodic steam huff and puff. The calculation methods of gas oil contact, water oil contact, the oil volume enabled by injected nitrogen, and the formation volume of enriched oil zone are established. The methods are applied to a production well of heavy oil reservoir with bottom water in the Shengli Oilfield, showing that injecting nitrogen for 20 days, 13 days and 10 days can push water coning to the original water oil contact at nitrogen injection rates of 600, 900, and 1 200 m 3 /h (standard conditions), respectively. The technology can effectively control water coning and increase oil production during effective periods.

Clay Stabilization Agents - Their Effectiveness in High-Temperature Steam

Laboratory data indicated that commercially available clay stabilization polymers may be beneficial in maintaining greater sustained formation permeabilities in clayey formations subjected to high-temperature steam injection. Polymers evaluated varied in high-temperature clay stabilization properties and resistance to hydrochloric acid. Result from several field applications of one polymer are included. Introduction Steaming encompasses the entire recovery spectrum involving primary, secondary, and tertiary approaches. It has been reported that oil retrieved by steam methods represents 90% of all the oil produced by current enhanced recovery techniques. Steam recovery methods often are applied in low-temperature, poorly consolidated, shallow geological laydowns which frequently are characterized by high concentrations of clay minerals. When exposed to steam, these untreated clays may cause severe matrix permeability reduction. Sometimes this loss of rock permeability is not fully recoverable. As a consequence, reservoir depletion efficiency may be reduced. Therefore, it is plausible to predict that effective clay mineral control will play a vital role in steam recovery of hydrocarbons from clay-bearing formations.Sand problems can be caused by inadequate clay control because clay minerals often serve as cementing materials in rock formations. Should the clay swell or migrate, cementation between sand grains can be damaged or destroyed, resulting in sand production. This has been reported to be a recurring problem in numerous cyclic steam (huff ‘n’ puff) wells in which the produced sand periodically must be bailed out of the wellbore. Clay Damage Mechanisms Numerous forms of clay minerals exist in subterranean strata. Their permeability damage potential is related to structure, orientation, cation exchange capacity, and geological laydown pattern along with the existing cation environment. Clays can be classified into two basic types:expanding andlow water absorbing. Smectite (montmorillonite), a three-layer clay, is considered the most expandable in the presence of water, particularly fresh or low-salinity waters similar to those associated with steaming techniques. Mixed-layer clays, containing smectite intermixed with other clays, also are classified as expandable. In addition to causing pore plugging, expanding clays can result in a release of other clay and silica fines which tend to travel within the tortuosity of the interstices until points of lodgment or bridging occur. This can result in further restriction of pore-space dimensions and lower permeability, which are synonymous with reduced withdrawal rates. Low-water-adsorbing clays (e.g., kaolinite, illite, and chlorite) are common to many shallow as well as deep formations. Although these clays can be expected to cause less damage due to expansion than smectite, other formation damage associated with water-promoted disintegration, dispersion, and migration can occur.For an excellent description of clays most common to hydrocarbon-bearing reservoirs, reference is made to a paper by Hower. JPT P. 2121＾