Aslanyan, Arthur (TGT Oil & Gas Services) | Aslanyan, Irina (TGT Oil & Gas Services) | Karantharath, Radhakrishnan (TGT Oil & Gas Services) | Matveev, Sergey (TGT Oil & Gas Services) | Skutin, Vasilii (TGT Oil & Gas Services) | Garnyshev, Marat (TGT Oil & Gas Services) | Bevillon, Damien (Dubai Petroleum Establishment) | Mehrotra, Nagendra (Dubai Petroleum Establishment) | Suarez, Nelson (Dubai Petroleum Establishment)
Wellbore fluid flow profiles in both producers and injectors tend to change over time due to preferential depletion, formation damage, cross-flow, channelling or tubing or casing leaks. These changes can result in excess water production through channelling, coning, non-uniform water breakthrough (fingering) or out-of-zone injection – all leading to uneven flow, pressure and sweep profiles. Ignoring these complications can result in missing key points on reservoir behaviour, selecting wrong units for a 3D full-field flow model or misleading redevelopment planning. Therefore, it would be logical to check for changes in flow geometry before embarking on costly workovers, recompletion or infill drilling programs.
This paper compares and integrates the results of conventional Production Logging Tool (PLT) surveys that use spinners and multiphase sensors with those acquired by reservoir-oriented production logging surveys employing a combination of Spectral Noise Logging (SNL) [1,2] and High Precision Temperature (HPT) Logging [3–5]. PLT and HPT-SNL produce similar results when wellbore and completion conditions are good but they may differ dramatically in cases of non-uniform formation damage, channelling behind pipe or plugging of perforations by scale. Generally, HPT-SNL would assess the flow geometry and invaded zones of the reservoir while PLT would point out where fluid enters or leaves the wellbore or tubing.
The paper provides case studies from a mature offshore waterflooded field producing a mix of oil, gas, formation water and injection seawater, which complicates the identification of flow geometry and invasion zones and represents a challenge for reservoir engineers in developing proper drilling or workover programmes to target residual reserves [6, 7]. The HPT-SNL-PNL surveys and further studies described here led to successful workovers and drilling. The redevelopment results can be easily assessed by decline curve analysis.
Since 2007, Dubai Petroleum Establishment (DPE) has performed more than 150 integrated PLT-HPT-SNL surveys to monitor vertical wellbore injection and production profiles that resulted in valuable and often surprising findings including unexpected water breakthrough intervals, bypassed oil zones and layers and water channelling behind casing in producers and injectors. These findings, in turn, led to a better understanding of how water propagated through reservoir from injectors to producers and were used to calibrate a 3D full-field flow model and identify optimum infill drilling locations for the redevelopment of the highly fractured crestal area of the field.
Malay Basin is a relatively matured basin which has undergone exploration and production for more than three decades, mainly from stratigraphic units of Miocene to Late Oligocene. The matured nature of the basin has driven PETRONAS to evaluate the remaining deep play potentials.
DD is a deep prospect below D Field. Several pre-drill risks were identified during prospect maturation namely, high temperature (450F), high pressure (11000 psi) and poor reservoir quality with low porosity (6% to 12%) and low permeability of <1 mD. PCSB however decided to drill DD-1 due to its large four way dip closure (approximately 250 km2), volume in-place and potential to open up other deep plays.
DD-1 is PETRONAS’ first Ultra High Pressure High Temperature (HPHT) well, located in southern Malay Basin to evaluate gas in Group M (Early Oligocene age). It penetrated Group M in D Field and reached its final TD at 4350 m TVDSS. It recorded temperature and pressure of 488oF and 13900 psi respectively. DD-1 proved that the petroleum system is working for the deep play by intersecting several gas bearing sandstone units namely M20, M30, M60 and M70 (C1-nC5, total gas 5% to 13%). Reservoir effectiveness is the major issue - low porosities (3% to 8%) and extremely low permeability (0.0025mD). Well testing over M20 flowed gas to surface and was flared, however the testing was deemed inconclusive. The HPHT nature of the well also presented operational challenges such as drilling within narrow mud weight and fracture gradient margin and the availability of suitable HPHT logging tools.
Well results indicated that Group M was gas bearing; however at this stage is not commercially recoverable. The deep play potential remains to be commercially exploited but better understanding of natural fracture networks and the utilising of advanced technology will be required.
DD-1 well is located approximately 236 kilometers northeast of Kemaman Supply Base (KSB), in water depth of 75 meters offshore Peninsular Malaysia (Figure 1). The prospect basically lies below the existing D Field which is currently being produced from the shallower Group I, J, K and L reservoirs.
The primary objective of the proposed DD-1 is to evaluate the hydrocarbon potential of the Group M sandstones which are within a structural four-way dip closure, the first ever well to test Group M in D Field. DD-1 is PETRONAS’ first Ultra High Pressure High Temperature (HPHT) well; it was spudded on 01 March 2013 and after five months of drilling campaign, it successfully reached final TD at 4388 m MDDF on 18 July 2013. It experienced high temperature and high pressure of 488oF and 13900 psi at final TD.
Over the past decade, explosive development in downhole tools and measurement techniques has facilitated subsurface acquisition of rock and fluid data during drilling and testing. In addition to rock and rock-fluid data such as porosity, permeability, and fluid saturations, downhole tools enable measurement of fluid properties such as the gas/oil ratios (GOR), saturation pressure, fluid density and viscosity, compositions, and asphaltene gradient. Downhole fluid analysis (DFA) is accomplished through a combination of spectroscopic and fluorescence techniques coupled with density and viscosity measurements. Early acquisition of downhole rock and fluid data is extremely critical to appraising, planning, and executing fast-track projects to maximize the asset’s potential.
The potential benefits of early data acquisition demonstrate DFA technology as a quick solution for decision-making parameters in scoping productivity analysis. DFA results are later validated and adjusted by laboratory measurements for in-depth reservoir performance predictions. Furthermore, early DFA measurements aid in the acquisition of cleaner reservoir fluid samples, well testing and completion design, and establishing fluid gradients and reservoir connectivity. Proper planning, interpretation expertise, and knowledge of modeling techniques are necessary to exploit the information from DFA.
Using field examples of DFA measurements and laboratory results, we found that GOR and fluid composition by DFA measurements are fairly accurate with low uncertainties for black oils in comparison with laboratory data. However, in the case of volatile oils and gas condensates, the uncertainty seems to increase as the GOR increases, which is confirmed by a close comparison of DFA data with laboratory analysis of companion fluid samples. We investigated likely sources for these discrepancies, particularly with reference to the spectroscopic data interpretation and the models used to translate the spectroscopic response into fluid compositions and GOR. Different approaches can be used to improve composition and GOR estimates from the DFA results, including enhanced modeling techniques of the spectroscopic data.
The type of reservoir fluid and its pressure/volume/temperature (PVT) behavior plays a critical role in estimating in-place hydrocarbon volumes, planning for reservoir development strategies and production processes, facilities design, and the mitigation of flow-assurance problems. In addition, reservoir and facilities simulation studies to predict reservoir performance and facilities optimization require fluid models based on measured data to capture fluid property variations with changes in operating conditions. Thus, fluid properties data are vital for planning reservoir development very early in the exploration and predevelopment stages. However, acquisition of representative fluid samples and subsequent laboratory analysis usually take a long time, as much as 3 to 6 months, resulting in undesirable project delays. In this environment, downhole fluid analysis (DFA) (Mullins et al. 2005; Betancourt et al. 2007; Fujisawa et al. 2008) tools offer the significant advantage of obtaining fairly accurate in-situ fluid bulk properties such as fluid density, viscosity, and gas/oil ratio (GOR).
Chuah, Bengsoon (PETRONAS) | Soni, Sumit (PETRONAS) | Jalan, Shlok (PETRONAS) | Kartooti, Hooman (PETRONAS) | Fauzi B. Tg. A. Hamid, Tg. M. (PETRONAS) | Chan, Keng Seng (PETRONAS) | Masoudi, Rahim (PETRONAS)
It shall never be over-emphasized that the balance of cost and value is very crucial in determining the commercial feasibility of a field development or redevelopment project. The values are generated by wells that could fetch higher productivity and could effectively drain out larger reservoir hydrocarbon fluid volume. Well drilling and completion costs and their surface production supporting facilities costs have been steadily increasing in recent years. Subsurface engineering studies shall therefore also focus on optimizing the well placement and orientation, the well type and completion selection, the life-cycle control of well inflow and outflow, with the minimum well count to yield higher values.
This paper entails various methodologies of selecting drainage and injection points by combining the remaining mobile oil, current productivity, and current pressure depletion maps constructed from history matched reservoir simulation models. Base on predominant drive mechanisms in the reservoirs studied, governing parameters were coupled in 3 property groups and normalized individually. A known heuristic approach was also adapted to construct a Simulated Opportunity Index (SOI) map. A correlation between the SOI and recoverable reserve (EUR) was established by simulation prediction runs for each drainage or injection point selected, sand by sand in the studied reservoirs. The studied reservoir cases including a vast thin oil-rim reservoir, a huge multiple stacked reservoir, a complex compartmentalized reservoir, and a prolific deep-water reservoir.
Clustering the selected drainage and injection points in several sands to further maximize the well productivity, optimization of the inflow control for the selected commingled sands, and the design of cost effective completions, shall be addressed later sequentially in separate papers.
The technical challenge is getting difficult as fields are reaching maturity. The complexity and uncertainty of the field require a detail understanding of both reservoir characteristics and facilities performance in order to identify and optimally exploit the field potential. In multi layered reservoirs, substantial reserves is located in minor reservoirs that demand innovative solution for cost effective redevelopment. The wells drilled in later part of the brown field especially require maximizing reservoir contact, higher well productivity for higher recovery to justify the well cost. Various well architecture options with elaborated smart bottom-hole devices is being deployed to control drawdown and sand production. To achieve maximum recovery with suitable well architecture, meticulous selection of optimum drainage and injection point is critical to boosting recovery from a brown field. Drainage point can be selected once confidence over complex remaining oil evaluation is established. Qualitative and quantitative methodologies ranging from surveillance and performance evaluation to 3D models are used to establish drainage and injection points in matured or brown reservoirs.
“Sour Service” refers to a well environment containing Hydrogen Sulfide (H2S), which is naturally associated with acid conditions. It is well known that H2S is hazardous to human health, living organisms, and more generally to the environment. It is for this reason that wells found with Sour Gas were often carefully plugged and abandoned in the past. H2S can also lead to catastrophic brittle failure of drillstring components: the physical phenomenon associated with Sour Service Environments and affecting steel based products under applied or residual stress is known as H2S embrittlement or more specifically as Sulfide Stress Cracking (SSC).
With the increasing demand of gas worldwide, some highly sour oil and gas reservoirs are being explored, mainly in Russia, the Middle East, China and North America, and are now more and more associated with complex well profiles – such as deep reservoirs or extended reach wells. The use of high strength drill pipe is essential to achieve such drilling objectives; however it does represents significant technical challenges in terms of drill pipe integrity and operational safety with the current high strength grades available on the market, such as S-135 drill pipe. Because higher strength is generally detrimental to Sulfide Stress Cracking, innovative chemistries and new heat treatment processes are needed to push Sour Service material limits even further.
A new high strength drill pipe family has been developed to specifically address those challenges: these new grades exhibit a minimum Yield Strength (120 ksi) higher than the current Sour Service grades available on the market as described by the current industry standards (95ksi or 105 ksi Specified Minimum Yield Strength). In order to guarantee the SSC resistance of these high strength materials, pipes and tool joints are tested as per the NACE standards. A first string of this high strength material is already being commercialized and used for the first time in offshore wells in the North Sea.
The present work summarizes the results of analysis of unique experimental data on vertical heat flow variations in different geological structures obtained from 15 scientific supper-deep and deep boreholes drilled to the depths of 1600-12 262 m within Russian and ICDP programs. The new workflow was applied for the heat flow estimation which is based on (1) precise and detailed thermal conductivity measurements on more than 30 000 cores with the new emerging technologies, (2) usage of more than 100 equilibrium and non-equilibrium temperature logs, and (3) determination of conductive heat flow component within 20-100 m intervals along every borehole studied.
The data on conductive heat flow variations provides an estimate of vertical variations in the convective heat flow component. The latter reflects the information on variations in reservoir and formation properties and heat- and mass transfer processes in reservoirs and formations.
It was established that a conductive component of the heat flow varies between 70 and 100% for the boreholes studied with essential (up to 100%) increase in heat flow within upper depth intervals of 2-4 km in some cases. Terrestrial heat flow values established from the measurements in deep and super-deep boreholes exceed the previous experimental heat flow estimates by 30…130% depending on a region of drilling. During the previous estimates the heat flow values were obtained from the measurements in shallow boreholes and heat flow was determined from averaging temperature gradient and thermal conductivity along boreholes.
The established heat flow variations play an important role in the improvement of reliability of basin and petroleum system modeling and prediction of temperatures below the borehole depths. The use of calibrated heat flow distributions is shown to increase the confidence of such studies.
Experimental data on heat flow density and rock thermal properties (thermal conductivity and volumetric heat capacity) are critically important for basin and petroleum system modeling. The results of the modeling depend essentially on heat flow density values and thermal property values for the sedimentary basin under studying integrated in the model. The rock thermal properties determine formation thermal regime in its natural state as borehole as at thermal methods of EOR.
It is considered normally that satisfactory data on heat flow and thermal properties could be found in publications and it is a usual practice in oil/gas science and industry at basin and petroleum modeling at present.
Bream Field, in Australia’s Gippsland Basin, was originally developed in 1987 as a thin oil column development with gas cap re-injection. A satellite platform was installed in 1996 to capture resource not reachable from the original platform. After achieving 68% recovery, oil rates had fallen to the point that gas cap blowdown was commenced. Given the extremely strong natural pressure support seen in the Gippsland basin, a controlled blowdown was carried out to maximize oil recovery during gas export. As the water level approached the top of the structure, an assessment was carried out to determine the best use of the field infrastructure.
The result of this effort was a decision to utilize the field for gas storage while simultaneously achieving enhanced recovery. By refilling the Bream reservoir with dry gas from the Longford gas plant during the summer months, high liquid yield fields are able to be produced consistently throughout the year. Additionally, Bream gas deliverability capacity is increased in the high gas demand periods. As the dry gas moves through the reservoir, it contacts both residual oil and rich gas, becoming re-saturated with gas liquids. When this gas is re-produced, it will yield more liquids, raising the overall recovery of the oil by approximately 1%. Re-injection into the Bream reservoir began in 2013 and is proceeding as planned.
This paper will discuss the history of the Bream development, highlighting the analysis and planning that led to the recently implemented project. The management of this field demonstrates a number of techniques for maximizing hydrocarbon recovery over the life of a field, as well as considerations for maximizing economic value of the infrastructure.
Bream Field, in the southwestern part of the Gippsland Basin (Australia), was originally discovered in 1969 and first developed in 1987. It is produced by the Gippsland Basin Joint Venture (between Esso Australia Resources Pty Ltd and BHPBilliton Petroleum (Bass Strait) Pty Ltd), with EARPL as the operator. GBJV offshore infrastructure includes 19 platforms, 4 subsea installations, and a network of pipelines feeding the Longford Gas Plant (see Figure 1). Approximately 98% of the production from the basin has come from the GBJV, since start-up in 1969. Bream Field and its development have been described in several publications, including:
The Bream development history, along with the forward plan described here, provide an interesting case study that demonstrates how available technology and the market demands drive development decisions.
Obviously, improving hydrocarbon production concerning the increased demand of hydrocarbon is essential. Matrix stimulation and hydraulic fracturing (HF) are two common methods for reservoir stimulation, which are intended to improve the flow connection of the wellbore with reservoir body. Beside the remarkable effects of HF on production recovery, regarding to the size of the operation, HF treatment requires huge capital investments. In order to efficiently mitigate the risk of HF treatment, choosing the best candidate well is the first step of this process. Multi criteria decision making (MCDM) methods provide us a powerful tool to evaluate parameters, especially when some parameters are qualitative and experts' knowledge based. In this study, first 14 effective parameters have been recognized by a decision makers’ committee for choosing the candidate wells. Then the analytical hierarchy process (AHP) has been applied for assigning the quantitative weight of each parameter on candidate well selection. By mentioned procedure, the productivity is defined as the most significant factor while water cut and production method are the least influencing parameters in the candidate well selection.
Choosing an excellent candidate for treatment often ensures success, while selecting a poor candidate will normally end in failure. In this regard, a comprehensive approach is so vital to recognize the most effective parameters and their influence which is practically presented in this research.
While, due to the pressure decline, the recovery rate of Iranian hydrocarbon reservoirs is lowering, demand for crude oil and its products are growing up fast. In this challenging situation, implementing supplementary production methods to increase the rate of recovery in a short time is indispensable. It should be noted that the oil and gas industry is aiming to reach a rate of recovery of 50% for oil and more than 80% for gas (Rückheim et al., 2005).
Reservoir stimulation, especially hydraulic fracturing (HF) is one of the main activities, which aims to enhance hydrocarbon recovery by the faster delivery of the petroleum fluid. Fundamentally, HF by improving the connections of the wellbore with the reservoir, helps wells to produce hydrocarbon fluides more quickly (Economides and Nolte, 2000; Daneshy, 2010). Although HF treatment has significant effects on hydrocarbon production recovery, it requires huge capital investments. So, the potential risk of failure must be recognized and mitigated before operation. Generally the first step of pre-operation deliberation is selecting a target well and a target formation. Choosing an excellent candidate for treatment often ensures success, while choosing a poor candidate will normally end in failure (Vincent, 2011; Malik et al., 2006).
Tarim carbonate reservoirs have been produced by Sinopec NW and Petrochina Tarim Oil Company since the late 1990's. Oil production from Tarim carbonates gradually increased during the last 15 years to reach close to 9.5 million tons (67 million bbl) in 2012, with an estimated 83 million ton total - almost 600 million bbl - extracted from the beginning. The oil extracted from these deep karst carbonate formations is contained in cave systems, and the dynamic and recovery behavior of these reservoirs is completely different from conventional matrix reservoirs.
The estimation of recoverable reserves in this type of reservoir is a major challenge. The determination of volumes, fluid saturations, and recovery factors is equally difficult for the three. Regarding volumes we discuss here some interesting consequences of the statistics of cave geometries, but a lot of work remains to be done in order to develop a practical method for volumes and average saturation determination.
The main contribution of this work is the development of a theoretical method to estimate oil recovery factors in karst reservoirs based on the modeling of the geomorphology of caves. According to this model buoyancy forces trap the oil in a multitude of attic pockets in the ceiling of caves. The trapping of the oil is the consequence of the extremely tight matrix, with zero permeability to oil, surrounding the open caves in Tarim Ordovician carbonate fields. The parameters of the mathematical cave model were calibrated using a 3D LIDAR survey of Shihua cave in an Ordovician carbonate outcrop near Beijing. More than five hundred random caves were generated on a computer and calculations of the volume of attic traps were carried out to determine oil recovery factors as a function of various parameters, such as the initial water level in the caves, or the position of the producing well.
This work shows for the first time that oil recovery factors in cave systems of Tarim basin can be surprisingly low despite the fact that oil is not capillary bound to the rock. This new understanding of karst reservoirs led to propose a new oil recovery method: using nitrogen as a displacement fluid. Nitrogen foam EOR has the potential to at least double oil recovery factors in Tarim carbonate reservoirs. The additional amount of oil that could be extracted from TaHe field alone could exceed 115 million tons (800+ million bbl). If applied to all Tarim carbonate fields the incremental oil production could exceed 200 million tons, i.e. well above one billion barrels.
Oil production history in Tarim basin carbonate oilfields
Tarim basin is located in the Xinjiang province in West China. Tarim carbonate reservoirs have been produced by Sinopec NW and Petrochina Tarim Oil Company (TOC) since the late 1990's. Oil production from Tarim carbonates gradually increased during the last 15 years to reach close to 9.5 million tons (67 million bbl) in 2012, with an estimated 83 million ton total (almost 600 million bbl) extracted from the beginning.
Petrochina TOC is developing several carbonate fields including Tazhong in central Tarim, and Lungu field in the North. Sinopec NW is exploiting the TaHe oilfield which represented more than 75% of the total oil extracted from Tarim carbonates since 1997 (Fig.1).
There are signs that TaHe field production is getting close to peak, and it will be difficult to avoid the decline of production using current field development methods. But finding new ways to increase production requires a good understanding of the reservoir production and recovery behaviour, which is the key objective of the work presented here.
This paper addresses the impact of acquiring a new 3D Broadband seismic survey over an amplitude-supported, discovered gas field containing legacy 3D conventional towed streamer seismic data. The new seismic data were acquired in shallow water depths using Western Geco’s dual level streamer technique and processed through PreSDM. Five gas discovery/appraisal wells with reservoirs ranging from approximately 1.2 to 2.5 s TWT (3,500 ft TVDss to 9,500 ft TVDss) existed prior to broadband acquisition and two additional wells were drilled after acquisition was completed. These seven wells serve as control points that provide a valuable link between the seismic and reservoir properties.
Acquisition of new seismic data was primarily motivated by imaging challenges, particularly in the deeper (>1.6 s TWT) section, to which legacy surveys and (re)processing attempts have failed to completely find a solution. These imaging problems stem from: 1) Abundant shallow gas pockets, which contribute to both amplitude and frequency decay in the underlying image; 2) Fault shadow noise resulting from velocity variations which are difficult to capture in the velocity model; and 3) The presence of sub-regional coal layers having high-impedance contrasts that further attenuate the signal and contribute to generation of multiples. A complimentary paper discusses the novel processing techniques applied to overcome these problems. Here, we discuss the comparative benefit of the broadband acquisition versus the legacy conventional acquisition, namely higher signal to noise ratio throughout the entire record. In this context, we demonstrate through interpretation of broadband data that overall, complex geologic layers are better resolved versus conventionally acquired seismic data. We also compare conventional and broadband wavelets and discuss the implications for layer detection and resolution. This is particularly important for imaging and interpreting thin (<20 ft) reservoirs. We compare horizon-based attribute maps with legacy interpretation and address the implications for reservoir model building. We also apply various degrees of de-multiple algorithms and assess the resultant AVO effects. The broadband data has provided significant uplift in terms of reservoir detection and has thus bolstered confidence in our interpretation of thin, gas charged reservoirs.