Development characteristics, models and strategies for overseas oil and gas fields

Based on about 20 years of accumulated experience and knowledge of oil and gas field development in overseas countries and regions for China's oil companies, the development features, ideas, models and plan designing strategies of overseas oil and gas fields were comprehensively summarized. Overseas oil and gas field development has ten major features, such as non-identity project resource, diversity of contract type, complexity of cooperation model, and so on. The overseas oil and gas field development aims at the maximization of production and benefit during the limited contract period, so the overseas oil and gas field development models are established as giving priority to production by natural energy, building large-scale production capacity, putting into production as soon as possible, realizing high oil production recovery rate, and achieving rapid payback period of investment. According to the overseas contract mode, a set of strategies for overseas oil and gas field development plans were made. For tax systems contracts, the strategy is to adopt the mode of “first fat and then thinner, easier in the first and then harder”, that is, early investment pace, production increase rate, development workload and production were decided by the change of tax stipulated in the contract. For production share contracts, the strategy is to give priority to high production with a few wells at a high production recovery rate to increase the cost-oil and shorten the period of payback. For technical service contracts, the strategy is that the optimal production target and workload of the project were determined by the return on investment, so as to ensure that the peak production and stable production periods meet the contract requirements. Key words: overseas oil and gas field, development ideas, technical strategy, development model, contract type, development plan desig

Development features and affecting factors of natural depletion of sandstone reservoirs in Sudan

Most reservoirs in Sudan are medium to high porosity and permeability sandstone reservoirs, these reservoirs have been developed by natural depletion since put into production, and the development is characterized by sparse wells of high production, big pressure differential, delayed infill drilling and water flooding, and rapid investment recovery. H field, FN field and P field are bottom water drive light oil field, bottom water drive heavy oil field and stratified high pour point oil field respectively, and they are representative fields in Sudan. The production performance of the three oil fields features sparse well spacing and high plateau rate, short stable production period, rapid water cut increase and fast production decline. Commingled production results in poor inter-layer development and complicated residual oil distribution. On the basis of the above analysis, major affecting factors of Sudan sandstone reservoirs natural drive have been identified through lab experiments, field development plan and field monitoring. The high off-take rate is conducive to the increase of the contract period recovery and recovery factor; sparse well spacing based on crude mobility range and determining infill well production cutoff considering contract terms can be helpful for cost-effective development; barriers and inter-layers can be made use of to detain bottom water coning and to enhance the development effect of bottom water oilfields; and delayed water injection in stratified high pour point reservoirs has no effect on recovery factor during contract period. Key words: sandstone reservoir, depletion development, development characteristics, development policy, Suda

Classification and characterization of barrier-intercalation in sandy braided river reservoirs: Taking Hegli Oilfield of Muglad Basin in Sudan as an example

Based on comprehensive analysis of core data, well logs and outcrops, the barrier-intercalations in the sandy braided river of Hegli Oilfield, Muglad Basin, Sudan were classified and analyzed. The barrier-intercalations in single wells were identified using grey theory, which, in combination of the modern braided river deposit measurements, was used to establish the quantitative calculation formulas for different barrier-intercalations in different scale. Three hierarchies of the barrier-intercalations are developed in the sandy braided river reservoirs in the study area, including barriers between the two single layers, intercalations between the two single sandbodies and intercalations in a single braided river bar. The barriers are 700–1 500 m wide and 1 000–2 000 m long, in continuous sheet shape. The intercalations of abandoned channel are 170–350 m wide; the intercalations of chute are 60–100 m wide and 900–1 500 m long; and the intercalations of braided river bars are 100–400 m wide and 300–800 m long. Based on the constraint of barrier- intercalation scale, 3-D geological models which accurately delineate different types of barrier-intercalations were built by facies-control and stochastic modeling. Key words: sandy braided river, barrier-intercalation, channel, braided river bar, hierarchy analysis, characterization method, 3D modelin

Study on characteristics of well-test type curves for composite reservoir with sealing faults

The pressure response for the composite reservoirs with a sealing fault locating in inner and outer region is different, which neglected by previous researchers, would cause significant errors during well-test interpretations. Based on seepage theory, a well-test model of two-region radial composite reservoir with infinite outer boundary has been built in this study considering wellbore storage and skin effects. The solutions for this model and characteristics of the type curves have been analyzed by applying the method of mirror image, Laplace transformation and superposition principle, including a straight fault, a perpendicular fault and parallel faults cases. The study shows that the dimensionless pressure derivative curves would be obviously different in two cases: the well to fault distance is larger, and smaller than the half length of the inner-region radius. Therefore, type curves are presented with reasonable parameters to analyze the distance effect on the dynamic pressure response. The results in this study are of great significance for guiding the oil and gas composite reservoirs' production and optimizing the hydrocarbon recovery. Keywords: Composite reservoir, Sealing faults, Well-test interpretation, Dynamic pressure response, Superposition principl

A computational method of productivity forecast of a multi-angle fractured horizontal well using the discrete fracture model

Multi-staged fracturing for horizontal wells is an important technique of stimulation in a naturally-fractured reservoir (NFR). Due to the complexity of the in-situ stress and the impact of natural fractures, there is usually a certain angle between the hydraulic fractures and the wellbore, which makes the production forecast of the fractured horizontal well very difficult. Based on the discrete fracture model (DFM), a computational method for the productivity of a multi-angle fractured horizontal well in NFR is established. The result of a practical case shows that the error between the computing results and the field data is less than 5% for considering the effect of the arbitrary of natural fractures and the angular of hydraulic fractures. A sensitivity analysis that was carried out indicates that the angle between the fracture and the wellbore has a significant impact on the horizontal well productivity. With the increase of fracture aperture, the productivity increases. Due to the interference that exists between fractures, the higher the fracture numbers there are does not mean the better productivity is

Preliminary study on a depositional interface-based reservoir modeling method

According to the channel deposition process and response features, the reservoir modeling based on the depositional interface (DI) is extended from turbidite fans to fluvial sandstones, in order to reconstruct the deposition process and improve the architecture simulation of channel sands. The DI-based modeling of fluvial reservoir is conducted in four steps: (1) Use a simple harmonic oscillation (SHO) damping model with disturbance to generate river flow lines and then complete the beaded association of singe-genetic sands; (2) Identify the interfaces at ends of channels (point bars) to generate the point bar model; (3) Determine the stacking pattern inside channel (point bar), and fit the interfaces with such functions as hyperboloid, paraboloid and polynomial; and (4) Carry out random sampling using the trigonometric function of key parameters for lateral accretion bedding, to complete characterization of point bar. It is concluded that the DI-based modeling method well reproduces the depositional process of fluvial sandstones and finely characterizes the architecture units therein. Key words: DI-based modeling, depositional process, reservoir architecture unit, channel sand, reservoir modeling metho

Horizontal well inflow performance relationship in foamy heavy oil reservoirs

Based on the recovery feature, oil and gas relative permeability law and driving mechanism of foamy heavy oil reservoirs, inflow performance relationship of horizontal wells in this kind of reservoirs was studied using multi-component numerical simulation and reservoir engineering methods. A dimensionless IPR equation of horizontal wells in foamy heavy oil reservoirs was also presented. Applying foamy oil multi-component numerical simulation, the IPR curve of horizontal wells in foamy heavy oil reservoirs was obtained: when the average formation pressure is high, the right end of the IPR curve is slightly upturned which shows foamy oil characteristics; with the decrease of average formation pressure, the characteristics of conventional solution-gas-drive reservoirs begin to appear. After comparing the dimensionless IPR curve of foamy heavy oil reservoirs with that of conventional solution-gas-drive reservoirs, it was found that: when dimensionless pressure is high, for both of these two kinds of reservoirs, dimensionless pressure and dimensionless oil production basically display linear relationship; when dimensionless pressure is low, the right end of the IPR curve of foamy heavy oil reservoirs is slightly upturned and that of conventional solution-gas-drive reservoirs is downturned. The relative error between the oil production calculated by the dimensionless IPR equation of horizontal wells in foamy heavy oil reservoirs and actual oil production is less than 13%. This research result can be used to direct the development of foamy heavy oil reservoirs. Key words: foamy heavy oil, horizontal well, inflow performance, IPR curv

An Improved Steam Injection Model with the Consideration of Steam Override

The great difference in density between steam and liquid during wet steam injection always results in steam override, that is, steam gathers on the top of the pay zone. In this article, the equation for steam override coefficient was firstly established based on van Lookeren’s steam override theory and then radius of steam zone and hot fluid zone were derived according to a more realistic temperature distribution and an energy balance in the pay zone. On this basis, the equation for the reservoir heat efficiency with the consideration of steam override was developed. Next, predicted results of the new model were compared with these of another analytical model and CMG STARS (a mature commercial reservoir numerical simulator) to verify the accuracy of the new mathematical model. Finally, based on the validated model, we analyzed the effects of injection rate, steam quality and reservoir thickness on the reservoir heat efficiency. The results show that the new model can be simplified to the classic model (Marx-Langenheim model) under the condition of the steam override being not taken into account, which means the Marx-Langenheim model is corresponding to a special case of this new model. The new model is much closer to the actual situation compared to the Marx-Langenheim model because of considering steam override. Moreover, with the help of the new model, it is found that the reservoir heat efficiency is not much affected by injection rate and steam quality but significantly influenced by reservoir thickness, and to ensure that the reservoir can be heated effectively, the reservoir thickness should not be too small

Phase behavior and miscible mechanism in the displacement of crude oil with associated sour gas

International audienceThe re-injection of associated sour gas, with high H2S and CO2 content, into the reservoir is proposed to be an effective development method due to its low investment cost and high oil recovery. The aim of this work is to present the phase behavior and miscible mechanism of crude oil displaced by associated sour gas. Based on the equation of state and the phase equilibrium theory, the phase behavior of crude oil mixed with various gases (associated sour gas, H2S, CO2 and CH4) have been analyzed. Then, the miscibility of associated sour gas was determined by calculating its Minimum Miscible Pressure (MMP) and the effect of sour component fraction on miscibility was evaluated. Moreover, a series of numerical simulations modeling 1D slim-tube were conducted using a compositional simulator to study the miscible mechanism in the displacement of crude oil with associated sour gas. The results show that the injection of H2S can reduce the bubble point pressure of crude oil and therefore is beneficial to prevent the crude oil degassing; nevertheless, the injection of CO2 has little effect on it. The miscible ability of associated sour gas decreases as its sour component fraction decreases. It is observed that the crude oil displaced by associated sour gas and sweet gas both show a combined condensing/vaporizing mechanism, with miscible zone in the middle of transition zone. However, the vaporizing-gas drive mechanism is slightly stronger than the condensing-gas drive mechanism during the displacement by associated sour gas while is significantly stronger during the displacement by sweet gas

Distribution of remaining oil based on fine 3-D geological modelling and numerical reservoir simulation: a case of the northern block in Xingshugang Oilfield, China

Abstract As the Xingshugang Oilfield is in the late stage of development, a conventional geological model could not meet the needs of further enhancing oil recovery, and the establishment of a fine 3-D geological model, namely the 3-D reservoir architecture model, is urgently required. The 3-D reservoir architecture model has a strong advantage in the detailed characterization of the distribution of various architectural elements and flow baffles and barriers in 3-D space. Based on the abundant data from close well spacing, in combination with the understanding of sedimentary facies and reservoir architecture, this study builds the 3-D reservoir architecture model to show the spatial distribution of different architectural elements and intercalations (mud drapes) under the control of third-, fourth- and fifth-order bounding surfaces. The study then establishes the property model under the control of sedimentary facies (architectural elements). Subsequently, based on the fine 3-D geological model, the distribution of remaining oil is obtained after the numerical reservoir simulation. The remaining oil primarily lies in the port of channel bifurcation, the parts blocked by intercalations and abandoned channels, and the edges of different facies. This observation provides a theoretical basis for further development and adjustment